jan 5, 2018 meeting, agenda item #1 marked to show … · 1/5/2018 · committee, nepool vote, and...

NEPOOL PARTICIPANTS COMMITTEE JAN 5, 2018 MEETING, AGENDA ITEM #1

Marked to Show Changes from Draft Circulated on 12/20/17

3874 The ISO was asked what its plans were more broadly given discussions in the IMAPP

process for more holistic, “achieve”-style proposals to better integrate policy objectives into the

wholesale market. The ISO responded that it intended to hold off for now while waiting on the

FERC’s response to the ISO’sits CASPR Proposal.

The NESCOE representative read a statement on behalf of the six New England states

reflecting their concerns described below with the ISO’s final CASPR Proposal and the related

stakeholder process/efforts in considering CASPR. [Secretary’s note: the statement as read has

been provided to NEPOOL and is posted with the meeting materials.] In general the statement

reviewed the history of the effort from NESCOE’s perspective, expressed disappointment that

there wais not a consensus proposal, and expressed appreciation for the efforts of NEPOOL

members and ISO technical staff. NESCOE explained it was disheartened by the ISO’s late

changes to its proposal, which it viewed as being issued with little notice or explanation,

particularly in light of the Sstates’s uniform opposition on a stand-alone basis to the amendments

accepted in the CASPR Proposal. They were unhappy with that late break in process and

explained that effort wouldill be required to restore trust and the willingness of Sstates to work

within the stakeholder process. With that background, the NESCOE representative reported that

three of the six Sstates continued to support the CASPR Proposal primarily because it could

accommodate renewable resources that currently dido not qualify for exemption from the

Minimum Offer Price Rule under the Renewable Technology Resource (RTR) exemption and/or

is not harmful to their consumers. Three states reportedly opposed the ISO’s CASPR Proposal

primarily because it eliminateds the RTR exemption after FCA15 without a backstop and it

reduceds liquidity in the Substitution Auction by accepting the limits in inter-zonal substitution.

In short, those states were not persuaded that CASPR improved on the status quo. The

ISO-NE PUBLIC

Summary of ISO New England Board and Committee Meetings

January 5, 2018 Participants Committee Meeting

Since the last update, the Markets Committee, the System Planning and Reliability Committee,

the Audit and Finance Committee, and the Nominating and Governance Committee met on

December 21 in Holyoke.

The Markets Committee received an update on the Competitive Auctions for Sponsored Policy

Resources project and discussed the substance of the concerns raised at the Participants

Committee, NEPOOL vote, and other stakeholder perspectives. The Committee also reviewed

proposed changes to its committee charter. Finally, the Committee held an executive session to

discuss corporate goals for 2018.

The System Planning and Reliability Committee was provided with an overview of activities and

events that were a major focus during the late summer and fall of 2017, including preparations

for Forward Capacity Auction #12, ongoing implementation of Order 1000, the second phase of

the 2016 Economic Planning Study – NEPOOL Scenario Analysis, support for the MA DOER

review of RFP’s for clean energy, and Long-Term Load, Energy Efficiency, and Solar PV Forecasts.

In addition, the Committee also previewed activities anticipated to be a major focus for the first

quarter of 2018. Next, the Committee received an update on the system operations outlook for

Winter 2017-2018, and an update the Regional System Plan projects. The Committee then held

an executive session to discuss corporate goals for 2018.

The Audit and Finance Committee received a report on cyber security and the company’s

ongoing work plan. The Committee discussed the continued development of the cyber security

team and the GridEx IV exercise in which the Company recently participated. The Committee

then met in executive session to review the corporate goals for 2018 and to assess achievement

of 2017 corporate goals.

The Nominating and Governance Committee received a report on Joint Nominating Committee

activities, and received an update on the New England political environment. The Committee

also reviewed proposed changes to its committee charter. Next, the Committee discussed the

board evaluation process, including potential topics regarding ongoing director education.

Finally, the Committee reviewed its calendar for the upcoming year.

NEPOOL PARTICIPANTS COMMITTEEJAN 5, 2018 MEETING, AGENDA ITEM #3

January 3, 2018 Report NEPOOL PARTICIPANTS COMMITTEE

JAN 5, 2018 MEETING, AGENDA ITEM #6

Page ES-1

41536280.182

EXECUTIVE SUMMARY Status Report of Current Regulatory and Legal Proceedings

as of JANUARY 3, 2018

The following activity, as more fully described in the attached litigation report, has occurred since the report dated December 6, 2017 was circulated. New matters/proceedings since the last Report are preceded by an asterisk ‘*’. Page numbers precede the matter description.

I. Complaints/Section 206 Proceedings

* 2 Calpine/LS Power Delayed Resource Complaint (EL18-53)

Dec 21 Dec 22-Jan 3

Jan 2

Calpine/LS Power file Complaint; response and comments due Jan 4NEPOOL, ISO-NE, ConEd, Direct, Dominion, EPSA, Eversource, Exelon, National Grid, NESCOE, NextEra, NRG intervene ISO-NE answers (and urges the FERC to deny) the Complaint

2 Clear River Schedule 11 O&M Complaint (EL18-31)

Dec 7 Dec 7–12 Dec 14 Dec 22 Dec 29 Jan 2

NEP, TOs answer Clear River Complaint; NESCOE protests ComplaintGMP, MA DPU, MMWEC, NHEC, VPPSA, NEPGA intervene Clear River protests ISO-NE motion for dismissal as a party Clear River answers NEP, TOs’, NEPOOL, NESCOE responses ISO-NE answers Clear River’s Dec 14 pleading NEPOOL answers Clear River’s Dec 22 answer

5 Base ROE Complaint IV (2016) (EL16-64)

Dec 11 Dec 15 Dec 18 Dec 21 Jan 2

Oral argument on CAPS’ Dec 1 motion; hearings begin Hearings end Trial Judge Glazer schedules post-hearing oral argument for Feb 22 Participants file joint transcript corrections Judge Glazer approves joint transcript corrections

II. Rate, ICR, FCA, Cost Recovery Filings

7 ICR-Related Values and HQICCs – Annual Reconfiguration Auctions (ER18-371)

Dec 7-15 Dec 20

National Grid, NESCOE, Public Citizen, Eversource intervene NEPOOL files comments supporting the ARA Values

8 FCA12 Qualification Informational Filing (ER18-264)

Dec 7

Dec 13 Dec 20

ISO-NE submits answers Efficiency Maine Trust, CPower/Tesla protests CPower answers ISO-NE Dec 7 answer ISO-NE answers CPower Dec 13 answer; Efficiency Maine Trust answers ISO-NE’s Dec 7 answer

8 ICR-Related Values and HQICCs – 2021-22 Capacity Commitment Period (ER18-263)

Dec 18 FERC accepts ICR-Related Values and HQICCs, eff. Jan 6

9 Emera MPD OATT Attachment J Revision (ER18-210)

Dec 8

Dec 12 Dec 19

Emera Maine requests FERC stay action on its Maine’s tariff filing pending its filing of an Answer to the Nov 22 MCG Protest Emera Maine refiles its Dec 8 request with correct eTariff filing code Emera Maine answers MCG Protest and lifts stay, stating that action on its filing is not needed before Jan 31; new comment date Jan 9

9 Exelon Additional Cost Recovery Compliance Filing (ER17-933)

Dec 18 FERC accepts compliance filing



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III. Market Rule and Information Policy Changes, Interpretations and Waiver Requests

* 10 ART Market Rule Changes (ER18-455)

Dec 15 Dec 18-21

Dec 20

ISO-NE and NEPOOL jointly file changes; comment date Jan 5 Brookfield, ConEd, Dominion, Exelon, National Grid, NESCOE, NRG intervene ISO-NE submits errata with correct clean tariff sheets for eLibrary

10 Waiver Request: Dispatchable Resources RTU Req. (McCallum Enterprises) (ER17-1615)

Dec 8 McCallum withdraws waiver request

IV. OATT Amendments / TOAs / Coordination Agreements

No Activity to Report

V. Financial Assurance/Billing Policy Amendments


VI. Schedule 20/21/22/23 Changes

* 12 Schedule 20A-GMP: Brookfield Complaint (EL18-52)

Dec 18 Dec 19 Dec 20

Dec 21-Jan 3

Brookfield files Complaint GMP opposes Brookfield request for fast track processing Brookfield answers GMP Dec 19 motion; FERC sets comment date as Jan 8 IRH, HQUS, Unitil, Schedule 20A Service Providers intervene

12 Schedule 21-EM: Stored Solar J&WE LSA (ER18-387)

Dec 13

Jan 3

ISO-NE and Emera re-submit Dec 5 filing so that it includes clean version of LSA Emera Maine submits second supplement to Dec filing; comment date Jan 24

12 Schedule 22: Clear River LGIA (ER18-349)

Dec 7 Dec 20

NESCOE intervenes Clear River protests filing

13 Eversource Reorganization Tariff Changes (ER18-132)

Dec 20 FERC accepts changes to Schedules 20A-NSTAR, 20A-ES, 21-NSTAR 21-ES, and the Attach. F & Sched. 1 Implementation Rules, eff. Jan 1

VII. NEPOOL Agreement/Participants Agreement Amendments


VIII. Regional Reports

* 15 IMM Quarterly Markets Reports - 2017 Summer (ZZ17-4)

Dec 20 IMM files Summer 2017 Report

IX. Membership Filings

* 15 January 2018 Membership Filing (ER18-539)

Dec 26 Terminations: Aspirity Energy, Constellation Energy Services, Noble Americas Power & Gas; comment date Jan 16

16 Suspension Notice – Plant-E Corp. (not docketed)

Dec 29 ISO files notice of suspension of Plant-E Corp. from New England Markets



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X. Misc. - ERO Rules, Filings; Reliability Standards

* 16 NOPR: Cyber Security Incident Reporting Reliability Standards (RM18-2)

Dec 21 FERC issues NOPR proposing to direct NERC to develop and file modifications to the CIP Standards to improve the reporting of Cyber Security Incidents; comment date Feb 26

17 NOPR: Revised Reliability Standard: CIP-003-7 (RM17-11)

Dec 22-26 NERC, ELCON, TAPS, Trade Associations file comments urging the FERC to approve the CIP-003-7 Changes; J. Applebaum submits adverse comments

19 Rules of Procedure Changes (Appendix D) (RR18-1)

Dec 8 Dominion intervenes

XI. Misc. - of Regional Interest

* 19 203 Application: PSNH/HSE Hydro NE (EC18-42)

Dec 28 PSNH and HSE Hydro NE request authorization for HSE Hydro NE to acquire PSNH’s portfolio of hydroelectric generation assets; comment date Jan 18

20 203 Application: PSNH/Granite Shore (EC18-12)

Dec 15

Dec 27

NH PUC requests expedited consideration of application and issuance of an order by Dec 28, 2017 FERC approves Granite Shore’s acquisition of PSNH generation assets

20 203 Application: WMECO /NSTAR Merger (EC17-62)

Jan 3 Eversource files notice that merger was consummated on Dec 31, 2017

* 21 LGIA: Emera Maine/Penobscot Energy Recovery Co (ER18-505)

Dec 21 Emera Maine files fully executed, non-conforming LGIA; comment date Jan 11

* 21 Third Supplement to Lease Agreement: UI/CT DOT (ER18-454)

Dec 14 UI files amendment; comment date Jan 4

* 22 Anbaric’s Ocean Grid Project: Transmission Rights at Negotiated Rates (ER18-435)

Dec 13

Jan 3

Anbaric Development Partners requests FERC authorization to sell transmission rights at negotiated rates on its Ocean Grid Project Bay State Wind LLC intervenes

* 22 IA: NSTAR/Covanta SEMASS (ER18-424)

Dec 11 NSTAR files IA with Covanta to replace an Oct 31, 1985 Power Sale Agreement between the parties which expired on Dec 1 and to recognize that Covanta now uses the New England transmission system to market the output of its 80 MW Rochester, MA facility

22 NEP/HQUS Phase I/II HVDC-TF Service Agreement (ER18-388)

Dec 26 HQUS submits comments supporting filing and requesting that the Service Agreement be accepted as filed

23 IA: PSNH/Pontook (ER17-2449) Dec 13 FERC accepts IA, eff. Dec 16, 2016 as requested

XII. Misc. - Administrative & Rulemaking Proceedings

24 NOI: FERC's Policy for Income Tax Cost Recovery & ROE Policies (PL17-1)

Jan 2 R. Gordon Gooch files motion requesting FERC to compel all pass-through entities to reduce their claims for income tax allowance in rates in response to “Tax Cut and Jobs Act”

24 DOE-Initiated Proposal: Grid Reliability & Resilience Pricing Rule (RM18-1)

Dec 7

Dec 8 Dec 12-26

FERC Chairman McIntyre requests 30-day extension of time for FERC action on NOPR DOE Sec. Perry grants extension to Jan 11, 2018 FRS, Global Energy Institute, Murray Energy, and certain public interest orgs. and individuals file supplemental comments, information and answers



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26 NOPR: Fast-Start Pricing in RTO/ISO Markets (RM17-3)

Dec 21 FERC withdraws Dec 2016 Fast-Start Pricing NOPR

XIII. Natural Gas Proceedings

31 New England Pipeline Proceedings • Atlantic Bridge Project (CP16-9) Dec 13

Dec 21

FERC denies rehearing of Jan 25, 2017 order authorizing Algonquin and Maritimes to construct and operate the Atlantic Bridge Project FERC denies rehearing of notices to proceed, variance approvals, and grant of in-service request

29 Natural Gas-Related Enforcement Actions: BP (IN13-15).

Dec 11

Dec 13 Dec 14

BP moves to reopen the proceeding, and to dismiss, or in the alternative, for reconsideration FERC Staff asks for additional time to respond to BP’s Dec 11 motionFERC grants Staff additional time, to Jan 25, to file its Answer to BP’s Dec 11 motion

XIV. State Proceedings & Federal Legislative Proceedings

34 Massachusetts Emissions Allowance Auctions: Stakeholder Input on Auction Design Parameters

Dec 15

Dec 29

MassDEP files final amendments to correct errors for two facilities in the 2018 allowance allocations Amendments published in Massachusetts Register

XV. Federal Courts

35 FCM Resource Retirement Reforms (17-1275)

Dec 28 Constellation appeals FCM Resource Retirement Reforms orders; appearances due Feb 1

36 Demand Curve Changes (17-1110**)

Dec 12 NESCOE, CT PURA and CPV Towantic file Intervenors for Respondent Brief

36 FCA10 Results (16-1408) and FCA9 Results (16-1068)

Dec 14 Court schedules cases for oral argument on Feb 9, 2018



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M E M O R A N D U M

TO: NEPOOL Participants Committee Member and Alternates

FROM: Patrick M. Gerity, NEPOOL Counsel

DATE: January 3, 2018

RE: Status Report on Current Regional Wholesale Power and Transmission Arrangements Pending Before the Regulators, Legislatures, and Courts

We have summarized below the status of key ongoing proceedings relating to NEPOOL matters before the Federal Energy Regulatory Commission (“FERC”),1 state regulatory commissions, and the Federal Courts and legislatures through December 6, 2017. If you have questions, please contact us.


• Calpine/LS Power Delayed Resource Complaint (EL18-53) On December 21, 2017, Calpine Corporation (“Calpine”) and LS Power Associates (“LS Power”, and

together with Calpine, “Complainants”) filed a complaint (“Delayed Resource Complaint”) asking the FERC to adopt an interim change to the Tariff, to be effective for FCA12, "to ensure that a resource that is not reasonably expected to be operational during the 2021-22 Capacity Commitment Period is not permitted to interfere with efficient price formation and artificially suppress prices in FCA 12 by entering a zero dollar offer for its capacity" and to "require ISO-NE to work with its stakeholders to file Tariff modifications in time for [FCA13] addressing the requirements for a Delayed Resource to participate in future FCAs, resume receiving its Lock-In Price, and extend its Lock-In Period.” Complainants also asked for Fast Track Processing and a shortened comment period. Thus far, ISO-NE answered the Delayed Resource Complaint on January 2 (urging the FERC to deny the Complaint) and doc-less interventions have been filed by NEPOOL, ISO-NE, ConEd, Direct, Dominion, EPSA, Eversource, Exelon, National Grid, NESCOE, NextEra, and NRG. Additional protests, comments and must be filed on or before January 4. If you have any questions concerning this matter, please contact Joe Fagan (202-218-3901; [email protected]), Jamie Blackburn (202-218-3905; [email protected]), or Sebastian Lombardi (860-275-0663; [email protected]).

• Clear River Schedule 11 O&M Complaint (EL18-31) On November 17, 2017, Clear River Energy Center LLC (“Clear River”)2 filed a complaint against ISO-NE,

National Grid and the TOs (together, “Respondents”) requesting that the FERC direct ISO-NE to modify Tariff Schedule 11 (and all other Tariff provisions that implement the Operating and Maintenance Cost (“O&M Costs”) recovery provisions of Schedule 11) under which interconnection customers are or could be required to pay O&M Costs associated with the construction of Large Generator Interconnection Agreement (“LGIA”)-required network upgrades, and to direct National Grid to modify its Schedule 21-NEP to conform with the changes made to Schedule 11. Clear River claims that National Grid’s Direct Assignment Facilities Charge to Clear River of all

1 Capitalized terms used but not defined in this filing are intended to have the meanings given to such terms in the Second

Restated New England Power Pool Agreement (the “Second Restated NEPOOL Agreement”), the Participants Agreement, or the ISO New England Inc. (“ISO” or “ISO-NE”) Transmission, Markets and Services Tariff (the “Tariff”).

2 Clear River is an indirect, wholly-owned subsidiary of Invenergy Thermal Development LLC and thereby a Related Person to

Generation Sector member Invenergy Energy Management LLC (collectively, “Invenergy”). Clear River is developing a 1,080 MW natural gas generation facility to be located in Burrillville, Rhode Island (the “Clear River Project”). The Project will interconnect to transmission facilities owned by National Grid and operated by ISO-NE. To provide service, National Grid will construct certain new network facilities, upgrade others and relocate an existing 345 kV network facility (collectively, the “NGrid Network Upgrades”) at an estimated cost of about $60 million.

mailto:[email protected]





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costs associated with the Network Upgrades that National Grid will build to accommodate interconnection of the Clear River Project is inconsistent with Order 2003 and the charge, as well as the provisions of the ISO-NE Tariff that authorize such a charge, are unjust and unreasonable. Respondents’ answer and all interventions or protests were due on or before December 7, 2017.

On November 29, ISO-NE asked the FERC to dismiss ISO-NE as a party to the Clear River Complaint proceeding, explaining that the Tariff provisions at issue are among those which the Participating Transmission Owners (“PTOs”), rather than ISO-NE, have the right to establish and modify under section 205 of the Federal Power Act (“FPA”), and that, with no financial interest in the matter, ISO-NE is not a necessary party. Alternatively, ISO-NE answered the Clear River Complaint (should the FERC decline to dismiss ISO-NE from the proceeding), taking no position on either the merits of Clear River’s claims or on “the propriety of any relief Clear River requests”. On December 14, Clear River protested ISO-NE’s November 29 motion to be dismissed as a party to the Complaint. ISO-NE answered that protest on December 29.

In addition to pleadings addressing ISO-NE’s status as a party to the Complaint, NEPOOL filed comments and a protest on December 6 requesting that the FERC deny the Clear River Complaint on its merits or, to the extent the FERC grants any part of the Clear River Complaint, send consideration of any necessary Tariff changes through the NEPOOL process for appropriate stakeholder input before they are filed. On December 7, New England Power and the PTO AC answered the Complaint. NESOCE protested the Complaint. Doc-less interventions were filed by Calpine, CMEEC, CT AG, CT OCC, CPV Towantic, Dominion, Green Mountain Power (“GMP”), MA DPU, MMWEC, MPUC, NESCOE, NextEra, NHEC, NRG, VPPSA, and NEPGA (out-of-time). On December 22, Clear River also protested the responses by NEPOOL, NESCOE and National Grid. NEPOOL answered Clear River’s December 22 answer on January 2. This matter is pending before the FERC. If you have any questions concerning this matter, please contact Eric Runge (617-345-4735; [email protected]) or Jamie Blackburn (202-218-3905; [email protected]).

• NEPGA PER Adjustment Complaint (EL16-120) As previously reported, the FERC denied,3 on November 16, 2017, NEPGA’s request for clarification

and/or rehearing of the PER Complaint Order.4 In that request, NEPGA had asked for clarification that when the FERC “determines refunds [in this proceeding], it will direct the ISO to refund to capacity suppliers the difference between: (i) the PER Adjustment payments charged to capacity suppliers after the September 30, 2016 refund effective date, and (ii) the PER Adjustment payments that would have been charged to capacity suppliers if the PER Adjustment were calculated using a just and reasonable PER Strike Price.” In declining to grant NEPGA’s request for clarification and/or rehearing, the FERC stated that, “If in fact refunds are ordered (and we note that the Commission has not yet determined whether it will order refunds), NEPGA’s understanding of the Commission’s intended methodology is incorrect … the Commission intended for ISO-NE to use the difference between the former strike price and the LMP for event hours that occurred prior to September 30, 2016, and for ISO-NE to use the new strike price only for event hours that occur after September 30, 2016 … [t]he Commission’s order is clear in that it addresses a change to the calculation of the PER strike price as set forth in section 111.13.7.2.7.1.1.1 and such change is prospective only. The order does not, nor did the Commission intend it to, provide for any change to the Monthly PER values that fall prior to the September 30, 2016 change in the methodology of calculating the strike price. FPA section 206 prevents such an outcome.”5 Any challenges to the FERC’s PER Complaint Order and PER Complaint Rehearing Order must be filed in federal court on or before January 16, 2018.

3New England Power Generators Assoc., Inc. v. ISO New England Inc., 161 FERC ¶ 61,193 (Nov. 16, 2017) (“PER Complaint

Rehearing Order”).

4New England Power Generators Assoc., Inc. v. ISO New England Inc., 158 FERC ¶ 61,034 (Jan. 19, 2017) (“PER Complaint

Order”), reh’g and clarif. denied, 161 FERC ¶ 61,193 (Nov. 16, 2017).

5PER Complaint Rehearing Order at PP 11-12.





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• NEPGA PER Adjustment Complaint Settlement Agreement (ER17-2153) The PER Settlement remains pending before the FERC. As previously reported, the Settling Parties6

submitted, filed July 28, 2017,7 an Offer of Settlement and settlement materials (“PER Settlement”) to resolve the issue set for hearing and settlement judge procedures by the Commission in this proceeding.8

Under the PER Settlement, the ISO will calculate Adjusted Hourly Strike Price as the sum of the daily Strike Price (as calculated under the existing Tariff) and a newly-defined Hourly PER Adjustment. The Hourly PER Adjustment will be equal to the average over each hour of a newly-defined Five-Minute PER Strike Price Adjustment. The Five-Minute Strike Price Adjustment9 will be equal to any positive difference between a five-minute Thirty Minute Operating Reserves Clearing Price or Ten-Minute Non-Spinning Reserves Clearing Price that exceeds the maximum allowable reserves clearing prices for those reserves products (i.e., the Reserve Constraint Penalty Factors) in effect before December 2014. The PER Settlement does not resolve the issues of the applicability of the Strike Price methodology to FCA9, which will be subject to comment in response to the PER Settlement Agreement.10 The term sheet that formed the basis for the PER Settlement was supported by the Participants Committee at the June 27 session of the Summer Meeting. All parties in EL16-120 “are deemed to have intervened in Docket No. ER17-2153-000”.11

In comments filed August 16, the ISO neither supported nor objected to the proposed PER strike price methodology and requested that the Commission resolve how the Average Monthly PER will be

6 PER “Settling Parties” are: NEPGA, NESCOE, the Retail Energy Supply Association (“RESA”), NEPOOL, Exelon, H.Q. Energy

Services (U.S.) (“HQUS”), Eversource, Dominion, Entergy, NRG, and Cogentrix. Intervenors in the proceeding not opposing the Settlement (“Non-Opposing Intervenors”) are: the ISO, PSEG, Consolidated Edison Energy, Inc. (“ConEd”), Verso Corp., GenOn Energy Management LLC, National Grid, NextEra, the New Hampshire Electric Coop. (“NHEC”), and Calpine.

7 The Settlement was initially filed on July 26 under different eTariff codes and subsequently withdrawn in favor of the July 28

filing. The Docket Number (ER17-2153) remained the same. The withdrawal of the July 26 filing was accepted on August 31.

8See New England Power Generators Assoc., Inc. v. ISO New England Inc., 158 FERC ¶ 61,034 (Jan. 19, 2017), reh’g requested

(“PER Complaint Order”). The PER Complaint Order (i) granted in part NEPGA’s complaint and (ii) set in part for hearing and settlement judge procedures the question of the appropriate method of calculating the PER Strike Price under Market Rule 1 Section III.13.7.2.7.1.1.1. The FERC found that “for the period at issue in NEPGA’s complaint (September 30, 2016 – May 31, 2018), the PER mechanism has become unjust and unreasonable as a result of the interaction between the PER mechanism and the higher Reserve Constraint Penalty Factors.” Accordingly, the FERC required the ISO to revise the method by which it calculates the PER Strike Price as set forth in Tariff section III.13.7.2.7.1.1.1. But, finding NEPGA’s request that the PER Strike Price be increased by $250 per MWh “raises issues of material fact that cannot be resolved based upon the record before us and that are more appropriately addressed in the hearing and settlement judge procedures”, the FERC set the question of for hearing and settlement judge procedures under section 206 of the FPA. The FERC established a refund effective date of September 30, 2016 (the date of the complaint). In establishing a September 30, 2016 effective date, the FERC clarified that “any changes to the calculation of the PER Strike Price under ISO-NE Tariff section III.13.7.2.7.1.1.1 would be prospective only from September 30, 2016, as required by FPA section 206, and would not impact the application of any PER Adjustment occurring before September 30, 2016.” On February 15, NEPGA requested clarification of the PER Complaint Order with respect to the PER Adjustment payments charged to NEPGA’s members on capacity invoices issued after the refund effective date. Specifically, NEPGA asked for clarification that when the FERC “determines refunds, it will direct the ISO to refund to capacity suppliers the difference between: (i) the PER Adjustment payments charged to capacity suppliers after the September 30, 2016 refund effective date, and (ii) the PER Adjustment payments that would have been charged to capacity suppliers if the PER Adjustment were calculated using a just and reasonable PER Strike Price.” On Mar. 3, NESCOE and RESA answered NEPGA’s rehearing request. NEPGA answered those answers on Mar. 17. The FERC issued a tolling order on Mar. 16, 2017, affording it additional time to consider NEPGA’s request for rehearing, which remains pending.

9 Five-Minute PER Strike Price Adjustment will be calculated according to the following formula: Five-Minute PER Strike Price

Adjustment = MAX (Thirty Minute Operating Reserves Clearing Price - $500/MWh, 0) + MAX (Ten Minute Non-Spinning Reserves Clearing Price – Thirty Minute Operating Reserves Clearing Price - $850/MWh, 0).

10 In its PER Complaint Rehearing Order, the FERC clarified that it “intended for ISO-NE to use the difference between the

former strike price and the LMP for event hours that occurred prior to September 30, 2016, and for ISO-NE to use the new strike price only for event hours that occur after September 30, 2016 … [t]he Commission’s order is clear in that it addresses a change to the calculation of the PER strike price as set forth in section 111.13.7.2.7.1.1.1 and such change is prospective only.”

11 Prior to Chief Judge Cintron’s order, the following parties filed doc-less interventions in ER17-2153: Calpine, ConEd, Entergy,

Eversource, Exelon, HQUS, NEPGA, NESCOE, NRG/GenOn, and RESA.



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calculated on and after June 1, 2018. NEPOOL, NEPGA, NESCOE, and Eversource filed comments supporting the PER Settlement. Comments by FERC Trial Staff indicated that it did not oppose the PER Settlement. In reply comments, NESCOE asked the FERC to reject the position advocated by NEPGA that the agreed-upon Adjusted Hourly Strike Price as defined in the Settlement should extend beyond May 31, 2018). NEPGA, NRG, HQUS, Dominion, and Verso jointly asked the FERC to approve the Settlement and order the ISO to make a compliance filing, but decline to address NESCOE’s request until some later date. Settlement Judge Young certified the uncontested settlement to the FERC on August 31, which remains pending before the Commission. If you have any questions concerning this matter, please contact Joe Fagan (202-218-3901; [email protected]), Jamie Blackburn (202-218-3905; [email protected]), or Sebastian Lombardi (860-275-0663; [email protected]).

• Base ROE Complaint IV (2016) (EL16-64) Hearings in this matter were held December 11-15, 2017. Transcripts of the hearings are posted on

the FERC’s eLibrary. Corrections to the transcripts, jointly filed by the hearing participants, were accepted by Judge Glazer on January 2. At the request of the parties, Judge Glazer scheduled post-hearing briefs’ oral argument for February 22. EMCOS, CAPS, TOs and FERC Trial Staff will each be allotted 30 minutes for argument. An initial decision is expected to be issued on or before March 27, 2018.

As previously reported, the FERC, on September 20, 2016, established hearing and settlement judge procedures (and set a refund effective date of April 29, 2016) for the 4th ROE Complaint filed by EMCOS on April 29, 2016.12 The 4th ROE Complaint asked the FERC to reduce the TOs’ current 10.57% return on equity (“Base ROE”) to 8.93% and to determine that the upper end of the zone of reasonableness (which sets the incentives cap) is no higher than 11.24%. EMCOS identified three main considerations requiring submission of this 4th ROE Complaint: (1) the continuing decline of the market cost of equity capital, which makes TOs’ currently authorized ROE “excessive, unjust and unreasonable, and therefore ripe for adjustment under FPA Section 206”; (2) “divergent rulings concerning the persistence of the “anomalous” capital market conditions”; and (3) “the extent to which the Commission’s anomalous conditions rationale in Opinion No. 531 is intended to reflect changes in its long-standing reliance on the discounted cash flow (“DCF”) methodology, and particularly the DCF midpoint, for determining ROE remains unclear.” Both the TOs and EEI requested rehearing of the Base ROE Complaint IV Order. The FERC issued a tolling order on November 21, 2016, affording it additional time to consider the requests for rehearing, which remain pending.

If you have any questions concerning this matter, please contact Eric Runge (617-345-4735; [email protected]) or Jamie Blackburn (202-218-3905; [email protected]).

• Base ROE Complaints I-IV: TOs’ Motion to Dismiss or Consolidate Complaints I-IV (EL16-64; EL14-86; EL13-33; EL11-66) The TOs’ October 5, 2017 motion to dismiss of all four ROE complaints (captioned above) in light of

the Emera Maine13 decision remains pending. The October 5 motion alternatively requested that the FERC consolidate the four ROE complaints for decision and use expedited procedures to resolve them. The TOs stated that this motion was motivated in part by Emera Maine, but also by what they describe as the “enormous investment uncertainty” resulting from the various litigation proceedings. On October 20,

12Belmont Mun. Light Dept. et al. v. Central Me. Power Co. et al., 156 FERC ¶ 61,198 (Sep. 20, 2016) (“Base ROE Complaint IV

Order”).

13Emera Maine v. FERC, 854 F.3d 9 (D.C. Cir. 2017) (“Emera Maine”). Emera Maine vacated the FERC’s prior orders in the Base

ROE Complaint I proceeding, and remanded the case for further proceedings consistent with its order. The Court agreed with both the TOs (that the FERC did not meet the Section 206 obligation to first find the existing rate unlawful before setting the new rate) and “Customers” (that the 10.57% ROE was not based on reasoned decision-making, and was a departure from past precedent of setting the ROE at the midpoint of the zone of reasonableness).








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Complainant-Aligned Parties and EMCOS submitted answers opposing TOs’ requests. The TOs’ motion and the motions filed in response are pending before the FERC.

• 206 Proceeding: RNS/LNS Rates and Rate Protocols (EL16-19) Settlement discussions in this proceeding are on-going. As previously reported, the FERC instituted this

Section 206 proceeding on December 28, 2015, finding that the ISO Tariff is unjust, unreasonable, and unduly discriminatory or preferential because the Tariff “lacks adequate transparency and challenge procedures with regard to the formula rates” for Regional Network Service (“RNS”) and Local Network Service (“LNS”).14 The FERC also found that the RNS and LNS rates themselves “appear to be unjust, unreasonable, unduly discriminatory or preferential, or otherwise unlawful” because (i) “the formula rates appear to lack sufficient detail in order to determine how certain costs are derived and recovered in the formula rates” and “could result in an over-recovery of costs” due to the “the timing and synchronization of the RNS and LNS rates”.15

Accordingly, the FERC established hearing and settlement judge procedures to develop just and reasonable formula rate protocols to be included in the ISO-NE Tariff and to examine the justness and reasonableness of the RNS and LNS rates. The FERC encouraged the parties to make every effort to settle this matter before hearing procedures are commenced.16 Hearings continue to be held in abeyance pending the outcome of settlement judge procedures underway.17 The FERC-established refund date is January 4, 2016.18

Settlement Judge Procedures. As previously reported, John P. Dring was designated the Settlement Judge in these proceedings. Five settlement conferences were held in 2016: January 19, March 24, April 28, August 30, and November 18 (telephonically). Four settlement conferences were held in 2017: April 5, May 9, July 7, and November 13, 2017. A tenth settlement conference has been scheduled for January 9, 2018. Judge Dring’s most recent status report was issued on December 5, noting that the proceeding is taking longer than expected but that the parties are making progress toward settlement. Accordingly, he recommended that the settlement procedures be continued. The Transmission Committee is being kept apprised, as appropriate, of settlement efforts. If you have any questions concerning this matter, please contact Eric Runge (617-345-4735; [email protected]).

• Base ROE Complaints II & III (2012 & 2014) (EL13-33 and EL14-86) (consolidated) Judge Sterner’s findings and Initial Decision, and pleadings in response thereto, remain pending

before the FERC. As previously reported, the FERC, in response to second (EL13-33)19 and third (EL14-86)20

complaints regarding the TOs’ 11.14% Base ROE, issued orders establishing trial-type, evidentiary hearings and separate refund periods. The first, in EL13-33, was issued on June 19, 2014 and established a 15-month

14ISO New England Inc. Participating Transmission Owners Admin. Comm. et al., 153 FERC ¶ 61,343 (Dec. 28, 2015), reh’g

denied, 154 FERC ¶ 61,230 (Mar. 22, 2016).

15Id. at P 8.

16Id. at P 11.

17Id.

18 The notice of this proceeding was published in the Fed. Reg. on Jan. 4, 2016 (Vol. 81, No. 1) p. 89.

19 The 2012 Base ROE Complaint, filed by Environment Northeast (now known as Acadia Center), Greater Boston Real Estate

Board, National Consumer Law Center, and the NEPOOL Industrial Customer Coalition (“NICC”, and together, the “2012 Complainants”), challenged the TOs’ 11.14% return on equity, and seeks a reduction of the Base ROE to 8.7%.

20 The 2014 Base ROE Complaint, filed July 31, 2014 by the Massachusetts Attorney General (“MA AG”), together with a group

of State Advocates, Publicly Owned Entities, End Users, and End User Organizations (together, the “2014 ROE Complainants”), seeks to reduce the current 11.14% Base ROE to 8.84% (but in any case no more than 9.44%) and to cap the Combined ROE for all rate base components at 12.54%. 2014 ROE Complainants state that they submitted this Complaint seeking refund protection against payments based on a pre-incentives Base ROE of 11.14%, and a reduction in the Combined ROE, relief as yet not afforded through the prior ROE proceedings.




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refund period of December 27, 2012 through March 27, 2014;21 the second, in EL14-86, was issued on November 24, 2014, established a 15-month refund period beginning July 31, 2014,22 and, because of “common issues of law and fact”, consolidated the two proceedings for purposes of hearing and decision, with the FERC finding it “appropriate for the parties to litigate a separate ROE for each refund period.”23 The TOs requested rehearing of both orders. On May 14, 2015, the FERC denied rehearing of both orders.24 On July 13, 2015, the TOs appealed those orders to the DC Circuit Court of Appeals (see Section XIV below), and that appeal remains pending.

Hearings and Trial Judge Initial Decision. Initial hearings on these matters were completed on July 2, 2015. In mid-December 2015, Judge Sterner reopened the record for the limited purpose of having the DCF calculations re-run in accordance with the FERC’s preferred approach and re-submitted. A limited hearing on that supplemental information was held on February 1, 2016. On March 22, 2016, Judge Sterner issued his 939-paragraph, 371-page Initial Decision, which lowered the base ROEs for the EL13-33 and EL14-86 refund periods from 11.14% to 9.59% and 10.90%, respectively.25 The Decision also lowered the ROE ceilings. Judge Sterner’s decision, if upheld by the FERC, would result in refunds totaling as much as $100 million, largely concentrated in the EL13-33 refund period. Briefs on exceptions were filed by the TOs, Complainant-Aligned Parties (“CAPs”), EMCOS, and FERC Trial Staff on April 21, 2016; briefs opposing exceptions, on May 20, 2016. Judge Sterner’s findings and Initial Decision, and pleadings in response thereto, remain pending, and will be subject to challenge, before the FERC. The 2012/14 ROE Initial Decisionand its findings can be approved or rejected, in whole or in part.

If you have any questions concerning this matter, please contact Joe Fagan (202-218-3901; [email protected]) or Eric Runge (617-345-4735; [email protected]).


• ICR-Related Values and HQICCs – Annual Reconfiguration Auctions (ER18-371) On December 1, 2017, ISO-NE and NEPOOL jointly filed materials that identify the Installed Capacity

Requirement (“ICR”), Local Sourcing Requirements (“LSR”), Maximum Capacity Limits (“MCL”), Hydro Quebec Interconnection Capability Credits (“HQICCs”), and capacity requirement values for the System-Wide and Marginal Reliability Impact Capacity Demand Curves (collectively, the “ARA Values”) for the third Annual Reconfiguration Auction (“ARA”) for the 2018-19 Capability Year to be held March 1, 2018, the second ARA for the 2019-20 Capability Year to be held August 1, 2018, and the first ARA for the 2020-21 Capability Year to be held June 1, 2018. The ARA Values were supported by the Participants Committee at its November 3, 2017 meeting. A January 30, 2018 effective date was requested. Comments on this filing were due December 22, 2017. On December 20, NEPOOL filed comments supporting the ARA Values. Interventions were filed by Dominion, Eversource, National Grid, NESCOE, NRG, and Public Citizen. This

21Environment Northeast, et al. v. Bangor Hydro-Elec. Co., et al., 147 FERC ¶ 61,235 (June 19, 2014) (“2012 Base ROE Initial

Order”), reh’g denied, 151 FERC ¶ 61,125 (May 14, 2015).

22Mass. Att’y Gen. et al. -v- Bangor Hydro et al., 149 FERC ¶ 61,156 (Nov. 24, 2014), reh’g denied, 151 FERC ¶ 61,125 (May 14,

2015).

23Id. at P 27 (for the refund period covered by EL13-33 (i.e., Dec. 27, 2012 through Mar. 27, 2014), the ROE for that particular

15-month refund period should be based on the last six months of that period; the refund period in EL14-86 and for the prospective period, on the most recent financial data in the record).

24Environment Northeast, et al. v. Bangor Hydro-Elec. Co., et al. and Mass. Att’y Gen. et al. -v- Bangor Hydro et al., 151 FERC ¶

61,125 (May 14, 2015).

25Environment Northeast, et al. v. Bangor Hydro-Elec. Co., et al. and Mass. Att’y Gen. et al. -v- Bangor Hydro et al., 154 FERC ¶

63,024 (Mar. 22, 2016) (“2012/14 ROE Initial Decision”).





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matter is pending before the FERC. If you have any questions concerning this matter, please contact Eric Runge (617-345-4735; [email protected]).

• FCA12 Qualification Informational Filing (ER18-264) On November 7, 2017, ISO-NE submitted its informational filing (the “FCA12 Informational Filing”)

for qualification in FCA12. ISO-NE is required under Market Rule Section 13.8.1 to submit an informational filing with the FERC containing the determinations made by ISO-NE for the upcoming Forward Capacity Auction (“FCA”) at least 90 days prior to each auction. FCA12 is scheduled to begin February 5, 2018. The Informational Filing contained ISO-NE’s determinations that the same three Capacity Zones that were modelled for FCA11 will be modelled for FCA12 -- Southeastern New England (“SENE”), Northern New England (“NNE”) and Rest of Pool. SENE will again be modeled as import-constrained; NNE will be modeled as export-constrained. The Informational Filing reported that there will be 35,007 MW of existing capacity in FCA12 competing with 5,605 MW of new capacity under a Net ICR of 33,725 MW (ICR minus HQICCs). The ISO reported also that there were a total of 2,309 MW of Static, Export, and Administrative Export De-list bids. A summary of the De-list bids accepted and those rejected for reliability purposes was included in a privileged Attachment E.

Comments on the FCA12 Informational Filing were due November 22, 2017. There were two protests filed, one by Efficiency Maine Trust and the other jointly by Enerwise Global Technologies, Inc., d/b/a CPower and Tesla, Inc. (together, “CPower”). Efficiency Maine seeks modification of the determinations made for three of its energy efficiency (“EE”) resources that it believes were unjustly decreased. Efficiency Maine also requests that FERC direct ISO-NE to continue to work cooperatively with Efficiency Maine to address the methodology issue that gave rise to the dispute and to correct that methodology in time for FCA13 so that it otherwise accounts for EE resource not accounted for in the FCA12 filing. For their part, CPower challenges ISO-NE’s denial of CPower’s Renewable Technology Resources (“RTR”) status request for certain of its already qualified new On-Peak Demand Resources utilizing renewable technologies (i.e., solar and fuel cells/solar projects), including Tesla’s renewable distributed resources. CPower asserts that ISO-NE has inconsistently interpreted Tariff Section III.13.1.1.1.7 to require a new On-Peak Demand Resource to demonstrate both that it currently qualifies under a state renewable or alternative energy portfolio standard (“RPS”) and is currently receiving an out-of-market revenue source supported by such a program or a similar mechanism. CPower asks the FERC to direct ISO-NE to review RTR status for the New On-Peak Demand Resources consistent with the reality that new renewable resources are eligible to receive an out-of-market revenue source supported by an RPS program and, as a New Resource, will have a future in-service date given the anticipated Capacity Delivery Period. Doc-less interventions were filed by NEPOOL, Dominion, Eversource, NRG, and NESCOE.

Since the last Report, on December 7, ISO-NE answered the CPower and Efficiency Maine protests. CPower answered the December 7 ISO-NE answer on December 13; Efficiency Maine Trust answered the ISO-NE December 7 answer on December 20. This matter remains pending before the FERC. If you have any questions concerning this matter, please contact Sebastian Lombardi (860-275-0663; [email protected]).

• ICR-Related Values and HQICCs – 2021-22 Capacity Commitment Period (ER18-263) On December 18, 2017, the FERC accepted the ICR, LSR for SENE, MCL for NNE, HQICCs, and Marginal

Reliability Impact (“MRI”) Demand Curves (collectively, the “2021-22 ICR-Related Values”) for the 2021-22 Capacity Commitment Year. The 2021-22 ICR-Related Values were accepted effective as of January 6, 2018, as requested. Unless the December 18 order is challenged, this proceeding will be concluded. If you have any questions concerning this matter, please contact Eric Runge (617-345-4735; [email protected]).






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• Emera MPD OATT Attachment J Revision (ER18-210) As previously reported, Emera filed changes on November 1 to Attachment J of the MPD OATT to

permit adjustments to formula rate inputs (historical load, revenue, sales data) to reflect “known and measurable” anticipated changes, subject to a true-up. Emera stated that, absent an ability to adjust its formula rate calculations to account for material losses of load, like that of Houlton Water Company expected to occur early next year, Emera Maine will suffer a significant under-recovery in its transmission revenue requirement. A protest was filed by the Maine Customer Group (“MCG”),26 which identified a number of reasons why the asserted that the changes should be rejected, with the principal objection being the fact that “Emera already has a true-up mechanism in place under the MPD OATT to accommodate loss of Houlton load”. On December 8, Emera Maine requested that the FERC stay action on its November 1 tariff filing pending Emera Maine’s filing of an Answer to the MCG protest.27

On December 19, Emera Maine submitted its answer to the MCG protest and lifted the stay on the filing. In so doing, Emera Maine stated that action on the filing is not needed before January 31, 2018. Any further comments on this matter are due on or before January 9. If there are any questions on this matter, please contact Pat Gerity (860-275-0533; [email protected]).

• Exelon Additional Cost Recovery Compliance Filing (ER17-933) As previously reported, the FERC granted Exelon Generation Company’s (“Exelon’s”) request for

additional fuel cost recovery for all mitigated days from October through November 2016, including the October 1, 3, and 4, 2016, operating days, in an amount totaling $1,554,854, as calculated by the Internal Market Monitor (“IMM”) (slightly more than identified in the initial filing,28 plus reasonable regulatory costs incurred in connection with the filing (subject to an Exelon compliance filing detailing the actual regulatory costs).29 On November 20, Exelon submitted that compliance filing, detailing $97,188.90 in actual regulatory costs incurred and to be recovered in connection with its request for additional fuel cost recovery for Mystic Units 8 & 9. The additional costs have been billed to Market Participants and the FERC accepted the compliance filing on December 18, 2017. Unless the December 18 order is challenged, this proceeding will be concluded. If you have any questions concerning this mater, please contact Pat Gerity (860-275-0533; [email protected]).

• TOs’ Opinion 531-A Compliance Filing Undo (ER15-414) Rehearing remains pending of the FERC’s October 6, 2017 order rejecting the TOs’ June 5, 2017 filing

in this proceeding.30 As previously reported, the June 5 filing was designed to reinstate TOs’ transmission rates to those in place prior to the FERC’s orders later vacated by the DC Circuit’s Emera Maine31 decision. In its Order Rejecting Filing, the FERC required the TOs to continue collecting their ROEs currently on file, subject to a future FERC order. 32 The FERC explained that it will “order such refunds or surcharges as necessary to replace the rates set in the now-vacated order with the rates that the Commission ultimately determines to be just and reasonable in its order on remand” so as to “put the parties in the position that they would have been in but for [its] error.” For the time being, so as not to “significantly complicate the process of putting into effect whatever ROEs the Commission establishes on remand” or create

26 MCG consists of consists of: Maine’s Office of the Public Advocate (“MOPA”), Houlton Water Company (“Houlton”), Van

Buren Light and Power District (“Van Buren”), and Eastern Maine Electric Cooperative, Inc. (“EMEC”).

27 On December 12, Emera Maine re-filed its request with the correct eFiling filing code.

28Exelon Generation Co., LLC, 160 FERC ¶ 61,076 (Sep. 20, 2017) (“Exelon Cost Recovery Order”).

29Id. at P 30.

30ISO New England Inc. et al., 161 FERC ¶ 61,031 (Oct. 6, 2017) (“Order Rejecting Filing”), reh’g requested.

31Emera Maine v. FERC, 854 F.3d 9 (D.C. Cir. 2017) (“Emera Maine”).

32Order Rejecting Filing at P 1.





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“unnecessary and detrimental variability in rates,” the FERC has temporarily left in place the ROEs set in Opinion 531-A, pending an order on remand.33 On November 6, the TOs requested rehearing of the Order Rejecting Filing. On December 4, the FERC issued a tolling order providing it additional time to consider the TOs’ request for rehearing of the Order Rejecting Filing, which remains pending. If you have any questions concerning this matter, please contact Joe Fagan (202-218-3901; [email protected]) or Eric Runge (617-345-4735; [email protected]).


• ART Market Rule Changes (ER18-455) On December 15, 2017, ISO-NE and NEPOOL jointly filed changes to establish a new capacity market

bilateral transaction -- an Annual Reconfiguration Transaction (“ART”) and to make other changes to the FCM rules (“CSO Transfer Improvements”).34 ISO-NE and NEPOOL requested that the CSO Transfer Improvements become effective in two stages, with most of the rule changes becoming effective on March 1, 2018 and the remainder becoming effective on June 1, 2018. The CSO Transfer Improvements were supported by the Participants Committee at the November 3 meeting (Agenda Item #7). Comments on this filing are due on or before January 5, 2018. Thus far, doc-less interventions have been filed by Brookfield, ConEd, Dominion, Exelon, National Grid, NESCOE, and NRG. If you have any questions concerning this proceeding, please contact Sebastian Lombardi (860-275-0663; [email protected]).

• Waiver Request: DR Auditing Requirements (CPower) (ER18-185) Enerwise Global Technologies Inc. d/b/a CPower Corp. (“CPower”) October 30, 2017 request for a one-

time waiver of Tariff Sections III.13.6.1.5.4.1(c) and III.13.6.1.5.4.5 remains pending. The waiver request would allow ISO-NE to use July 26 Real-Time Demand Response (“RTDR”) resource audit results as CPower’s July 2017 Demand Reduction Value, rather than Jul 19 results which, because of a “communications software anomaly”, produced “zero” reduction performance results. CPower explained that the communication software anomaly could be traced to an earlier July 12 outage at CPower’s leased data center, following which CPower’s Remote Terminal Unit (“RTU”) communications service was not fully and properly restored, preventing a July 19, 2017 dispatch signal sent as part of an audit to not be received, ultimately producing “zero” reduction performance. Following full restoration of the RTU service, a subsequent audit was requested and performed on July 26. The requested waiver would permit the July 26 Audit results to replace the zero July 19 Audit results as the Demand Reduction Value (and mitigate the financial impacts of the July 19 results). Comments on CPower’s waiver request were due on or before November 20. ISO-NE submitted comments opposing the waiver request (suggesting the request is not limited in scope, there is no concrete problem to be remedied and the likelihood that the waiver would result in unfavorable treatment to similarly-situated participants). NEPOOL submitted a doc-less intervention. As noted, this matter remains pending before the FERC. If you have any questions concerning this proceeding, please contact Pat Gerity (860-275-0533; [email protected]).

• Waiver Request: Dispatchable Resources RTU Requirement (McCallum Enterprises) (ER17-1615) On December 8, McCallum Enterprises (“McCallum”) withdrew its May 9 request for a waiver of a

portion of Market Rule Section 1.11.3, ending this proceeding. As previously reported, the requested waiver would have excused McCallum from the requirement under Section 1.11.3 to install a remote terminal unit (“RTU”) and the necessary circuitry to make its 7 MW the Derby Hydroelectric Project in Shelton electronically dispatchable. Based on information disclosed in this proceeding and further investigation and efforts, however, ISO-NE ultimately determined that the Derby facility was improperly registered as a non-intermittent generator, and that, if properly registered as an intermittent generator, the Facility would not be subject to the Resource Dispatchability rules from which McCallum sought a partial waiver. With the change registration complete, and

33Id. at P 36.

34 On December 20, ISO-NE submitted an errata filing to correct the clean Tariff sheets to be posted in eLibrary.







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the waiver no longer necessary, McCallum withdrew its request. If you have any questions concerning this matter, please contact Pat Gerity (860-275-0533; [email protected]).

• CONE & ORTP Updates (ER17-795)

Rehearing remains pending of the FERC’s October 6 order accepting updated FCM Cost of New Entry (“CONE”), Net CONE and Offer Review Trigger Price (“ORTP”) values filed by ISO-NE in January.35 In accepting the changes, the FERC disagreed with the challenges to ISO-NE’s choice of reference technology (gas-fired simple cycle combustion-turbine) and on-shore wind capacity factor (32%). The changes were accepted effective as of March 15, 2017, as requested. On November 6, NEPGA requested rehearing of the CONE/ORTP Updates Order. On December 4, the FERC issued a tolling order providing it additional time to consider NEPGA’s request for rehearing of the CONE/ORTP Updates Order, which remains pending. If you have any questions concerning this proceeding, please contact Sebastian Lombardi (860-275-0663; [email protected]).

• 2013/14 Winter Reliability Program Remand Proceeding (ER13-2266) Still pending before the FERC is ISO-NE’s compliance filing in response to the FERC’s August 8, 2016

remand order.36 In the 2013/14 Winter Reliability Program Remand Order, the FERC directed ISO-NE to request from Program participants the basis for their bids, including the process used to formulate the bids, and to file with the FERC a compilation of that information, an IMM analysis of that information, and the ISO’s recommendation as to the reasonableness of the bids, so that the FERC can further consider the question of whether the Bid Results were just and reasonable.37 ISO-NE submitted its compliance filing on January 23, 2017, reporting the IMM’s conclusion that “the auction was not structurally competitive and a ‘small proportion’ of the total cost of the program may be the result of the exercise of market power” but that the “vast majority of supply was offered at prices that appear reasonable and that, for a number of reasons, it is difficult to assess the impact of market power on cost.” Based on the IMM and additional analysis, the ISO recommended that “there is insufficient demonstration of market power to warrant modification of program.” In February 13 comments, both TransCanada and the MA AG protested ISO-NE’s conclusion and recommendation that modification of the program was unwarranted. TransCanada requested that FERC establish a settlement proceeding where market participants could “exchange confidential information to determine what the rates should be” and refunds and “such other relief as may be warranted” provided. On February 28, ISO-NE answered the TransCanada and MA AG protests. On March 10, 2017, TransCanada answered ISO-NE’s February 28 answer. This matter is again pending before the FERC. If you have any questions concerning these matters, please contact Sebastian Lombardi (860-275-0663; [email protected]).

IV. OATT Amendments / TOAs / Coordination Agreements




35ISO New England Inc., 161 FERC ¶ 61, 035 (Oct. 6, 2017 )(“CONE/ORTP Updates Order”), reh’g requested.

36ISO New England Inc., 156 FERC ¶ 61,097 (Aug. 8, 2016) (“2013/14 Winter Reliability Program Remand Order”). As previously

reported, the DC Circuit remanded the FERC’s decision in ER13-2266, agreeing with TransCanada that the record upon which the FERC relied is devoid of any evidence regarding how much of the 2013/14 Winter Reliability Program cost was attributable to profit and risk mark-up (without which the FERC could not properly assess whether the Program’s rates were just and reasonable), and directing the FERC to either offer a reasoned justification for the order in ER13-2266 or revise its disposition to ensure that the Program rates are just and reasonable. TransCanada Power Mktg. Ltd. v. FERC, 2015 U.S. App. LEXIS 22304 (D.C. Cir. 2015).

372013/14 Winter Reliability Program Remand Order at P 17.






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VI. Schedule 20/21/22/23 Changes

• Schedule 20A-GMP Brookfield Complaint (EL18-52) On December 18, Brookfield Energy Marketing LP (“Brookfield”) filed a complaint (“Brookfield

Complaint”) requesting that the FERC confirm the validity of its 10-year Phase I/II transmission service request (“TSR”) and require Green Mountain Power (“GMP”), the Schedule 20A Service Provider, to allocate 46 MW of Available Transfer Capability (“ATC”) at issue in accordance with the procedures set forth in Schedule 20A. Brookfield claims that GMP rejected the TSR because the TSR sought service for a duration in excess of the one-year offering GMP posted on OASIS and because GMP claims that its contractual rights to market the ATC at issue are limited to the one-year time period that was posted. Brookfield requested expedited consideration of the Complaint and a FERC order by December 31, 2017, pursuant to the FERC’s Fast Track procedures. On December 19, GMP opposed Brookfield request for Fast Track processing, which Brookfield answered on December 20. On December 20, the FERC issued a notice of the Complaint, which set the comment date at January 8, 2017. Doc-less interventions have thus far been submitted by the Interconnection Rights Holders Management Committee (“IRH”), HQUS, Unitil, and the Schedule 20A Service Providers.38 If there are questions on this matter, please contact Eric Runge (617-345-4735; [email protected]).

• Schedule 21-EM: Stored Solar J&WE LSA (ER18-387) On December 5, Emera Maine and ISO-NE filed a Local Service Agreement (“LSA”) by and among

Emera Maine, Stored Solar J&WE, and ISO-NE for Local Non-Firm Point-to-Point Transmission Service under Schedule 21-EM of the ISO-NE OATT (the “Stored Solar LSA”). The LSA extends the same discounted service rate to Stored Solar that was offered to its predecessors, Indeck Maine and Covanta Maine. A January 1, 2016 effective date (the date Stored Solar acquired the Jonesboro facility) was requested. Emera Maine and ISO-NE resubmitted the filing on December 13 to include a clean version of the Stored Solar LSA that was inadvertently not included in the December 5 filing. Comments on the LSA were due on or before December 26, 2017; comments on the first supplement were due January 3. No comments were filed on either of those filings. On January 3, ISO-NE and Emera Maine submitted a second supplement. The second supplement made addition corrections to the filing and included an elaboration by Emera Maine on why time value of money refunds are not appropriate under the circumstances presented by this matter. Comments on the second supplement will be due on or before January 24. If there are any questions on these matters, please contact Pat Gerity (860-275-0533; [email protected]).

• Schedule 22: Clear River LGIA (ER18-349) On November 29, ISO-NE and New England Power Company (“NEP” or “National Grid”) filed an

unexecuted Large Generator Interconnection Agreement (“LGIA”) by and among ISO-NE, NEP and Clear River to govern the interconnection of Clear River’s proposed new Large Generating Facility to be located in Burrillville, Rhode Island (the “Clear River Project”). ISO-NE reports that the Clear River LGIA is being filed unexecuted because Clear River disagrees with various aspects of the Clear River LGIA, including Clear River’s challenges regarding cost responsibility for upgrades and the post-FCA restudy. (See also Clear River Schedule 11 O&M Complaint, EL18-31, Section I above). A November 30, 2017 effective date was requested (to coincide with the date on which interconnection activities under the LGIA are expected to commence). Comments on the LGIA were due on or before December 20, 2017.

Clear River filed the only comments, a protest, on December 20. In its protest, Clear River asked that the FERC:

38 “Schedule 20A Service Providers” are self-described as “those public utility transmission providers who hold the rights to the

transmission capacity over the [HQ Interconnection] and who make those rights available on an open-access basis to transmission customers under Schedule 20A of the ISO-NE OATT” and “a subset of the IRH.”





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(1) direct ISO-NE to revise the LGIA’s milestone date by which the notice to proceed (“NTP”) must be issued and security posted; (2) direct [National Grid] to permit Clear River to exercise its option to build certain transmission owner interconnection facilities identified in the LGIA; (3) direct ISO-NE to reevaluate whether the upgrades identified in the LGIA and predicated on Clear River’s initially planned 2019 commercial operation date (“COD”) will still be necessary in light of Clear River having informed ISO-NE that due to unforeseeable permitting delays, Clear River had to extend the planned COD to 2021; (4) confirm that Clear River should be responsible for paying only for those facilities necessary to interconnect the Project and not for any oversized and therefore unnecessary equipment; (5) direct ISO-NE and [National Grid] to demonstrate that they considered whether there were more cost-effective upgrade options to address the impacts of interconnecting the Clear River Project; and (6) order that the LGIA be modified to state that [National Grid]’s ability to directly assign network upgrade-related O&M Costs to Clear River is subject to the [FERC]’s determination regarding the complaint filed by Clear River in Docket No. EL18- 31-000 on November 17, 2017.

Doc-less interventions were filed by NEPOOL, NESCOE and Dominion. This matter is pending before the FERC. If there are questions on this matter, please contact Eric Runge (617-345-4735; [email protected]).

• Schedule 21-NEP: National Grid/Graite Reliable Power RFA (ER18-346) On November 29, 2017, New England Power filed a Related Facilities Agreement (“RFA”) with

Granite Reliable Power, LLC (“Granite Reliable Power”) to address costs associated with upgrades to NEP’s equipment at the Moore Generating Station and modifications to NEP’s protection system in connection with the Dummer, New Hampshire interconnection of Granite Reliable Power’s 99 MW wind generation facility. A November 1, 2017 effective date was requested. Comments on this filing were due on or before December 20, 2017; none were filed. This matter is pending before the FERC. If you have any questions concerning this matter, please contact Pat Gerity ([email protected]; 860-275-0533).

• Eversource Reorganization Tariff Changes (ER18-132) On December 20, the FERC accepted tariff revisions filed by Eversource on October 23, 2017 to the

following portions of Section II of the ISO Tariff to reflect the new references to NSTAR Electric (East) and NSTAR Electric (West), which will be used to refer to the transmission services and rates previously provided separately by NSTAR Electric and WMECO, that will continue to be provided as if NSTAR Electric and WMECO were separate legal entities, until such future time as a filing can be made to allow for one set of books and records and to adjust rates as may be necessary: Schedules 21-NSTAR and 21-ES, Schedules 20A-NSTAR and 20A-ES, and the Attachment F and Schedule 1 Implementation Rules. The changes were accepted effective as of January 1, 2018. Unless the December 20 order is challenged, this proceeding will be concluded. If you have any questions concerning this matter, please contact Eric Runge (617-345-4735; [email protected]).

• Schedule 21-EM: Recovery of Bangor Hydro/Maine Public Service Merger-Related Costs (ER15-1434 et al.) On June 2, 2016, the FERC accepted, but established hearing and settlement judge procedures for,39

March 31 filings by Emera Maine in which Emera Maine sought authorization to recover certain merger-related costs viewed by the FERC’s Office of Enforcement’s Division of Audits and Accounting (“DAA”) to be subject to the conditions of the orders authorizing Emera Maine’s acquisition of, and ultimate merger with,

39Emera Maine and BHE Holdings, 155 FERC ¶ 61,230 (June 2, 2016) (“June 2 Order”).






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Maine Public Service (“Merger Conditions”). As previously reported, the Merger Conditions imposed a hold harmless requirement, and required a compliance filing demonstrating fulfillment of that requirement, should Emera Maine seek to recover transaction-related costs through any transmission rate. Following its recent audit of Emera Maine, DAA found that Emera Maine “inappropriately included the costs of four merger-related capital initiatives in its formula rate recovery mechanisms” and “did not properly record certain merger-related expenses incurred to consummate the merger transaction to appropriate non-operating expense accounts as required by [FERC] regulations [and] inappropriately included costs of merger-related activities through its formula rate recovery mechanisms” without first making a compliance filing as required by the merger orders.

In the June 2 Order, the FERC found that the Compliance Filings raise issues of material fact that could not be resolved based on the record, and are more appropriately addressed in the hearing and settlement judge procedures.40 The FERC reiterated several points with respect to transaction-related cost recovery explained in prior FERC orders and provided guidance on other transaction-related cost recovery points.41 The FERC encouraged the parties to make every effort to settle their disputes before hearing procedures are commenced, and will hold the hearing in abeyance pending the outcome of settlement judge procedures.42 The separate compliance filing dockets were consolidated for the purposes of settlement, hearing and decision.43

Settlement Judge Procedures. ALJ John Dring is the settlement judge for these proceedings. There have been five settlement conferences: three in 2016 -- June 29, October 25, and December 1; and two in 2017 -- September 6 and November 9, 2017. In his most recent November 21 status report, Judge Dring found that that the parties are making progress toward settlement, and recommended that settlement procedures (which are on-going) be continued.

Hearing Procedures? On October 11, Emera Maine requested that the Chief Judge establish an expedited hearing under specific terms and conditions set forth in Exhibit A to its October 11 motion (“Expedited Hearing”). The October 11 motion also asked that the answer period to its request be shortened to five days and that an order ruling on the motion be issued no later than October 18, 2017. On October 13, the Maine Customer Group, MPUC, ReEnergy Biomass Operations LLC, and FERC Trial Staff (collectively, “Intervenors and FERC Trial Staff”), filed an answer opposing the October 11 motion’s request for a shortened answer period. On October 13, Chief Judge Cintron issued an order (“October 13 Order”) which denied the request to shorten the answer period and identified additional questions that all participants in the proceeding were permitted the opportunity to address in their answers to the October 11 motion. Responses to the October 13 Order were filed by Emera Maine, Maine PUC/OPA, Maine Customer Group, and FERC Trial Staff (“October 26 Responses”). On November 13, Emera Maine responded to the October 26 Responses. The October 11 motion, October 26 Responses and Emera Maine’s answer to the October 26 Responses are pending before Chief Judge Cintron.

If you have any questions concerning these matters, please contact Pat Gerity ([email protected]; 860-275-0533).

40Id. at P 24.

41Id. at PP 25-26.

42Id. at P 27.

43Id. at P 21; Ordering Paragraph (B).




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VII. NEPOOL Agreement/Participants Agreement Amendments



• Opinion 531-A Local Refund Report: FG&E (EL11-66) FG&E’s June 29, 2015 refund report for its customers taking local service during Opinion 531-A’s

refund period remains pending. If there are questions on this matter, please contact Pat Gerity (860-275-0533; [email protected]).

• Opinions 531-A/531-B Regional Refund Reports (EL11-66) The TOs’ November 2, 2015 refund report documenting resettlements of regional transmission

charges by the ISO in compliance with Opinions No. 531-A44 and 531-B45 also remains pending. If there are questions on this matter, please contact Pat Gerity (860-275-0533; [email protected]).

• Opinions 531-A/531-B Local Refund Reports (EL11-66) The Opinions 531-A and 531-B refund reports filed by the following TOs for their customers taking

local service during the refund period also remain pending before the FERC:

♦ Central Maine Power ♦ National Grid ♦ United Illuminating

♦ Emera Maine ♦ NHT ♦ VT Transco

♦ Eversource ♦ NSTAR

If there are questions on this matter, please contact Pat Gerity (860-275-0533; [email protected]).

• IMM Quarterly Markets Reports - Summer 2017 (ZZ17-4) On December 20, the IMM filed with the FERC its report for the Summer quarter of 2017 of “market

data regularly collected by [it] in the course of carrying out its functions under … Appendix A and analysis of such market data,” as required pursuant to Section 12.2.2 of Appendix A to Market Rule 1. These filings are not noticed for public comment by the FERC, but the Summer 2017 will be discussed with the Markets Committee at its January 9 meeting.


• January 2018 Membership Filing (ER18-539) On December 26, NEPOOL requested that the FERC accept the termination of the Participant status of

Aspirity Energy (Supplier Sector), Constellation Energy Services [Related Person to Exelon Generation Company (Supplier Sector) and Noble Americas Power & Gas [Related Person to Mercuria Energy America (Supplier Sector)]. Comments on the December Membership filing are due on or before January 16.

• December 2017 Membership Filing (ER18-353) On November 30, NEPOOL requested that the FERC accept (i) the memberships of Fusion Solar Center

(Related Person to Deepwater Wind Rhode Island (AR Sector) and Josco Energy MA (Supplier Sector); and (ii) the name change of Supplier Sector member Summer Energy Northeast (f/k/a REP Energy). This matter is pending before the FERC.

44Martha Coakley, Mass. Att’y Gen. et al., 149 FERC ¶ 61,032 (Oct. 16, 2014) (“Opinion 531-A”).

45Martha Coakley, Mass. Att’y Gen. et al., Opinion No. 531-B, 150 FERC ¶ 61,165 (Mar. 3, 2015) (“Opinion 531-B”).






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• Suspension Notices (not docketed) Since the last Report, the ISO filed, pursuant to Section 2.3 of the Information Policy, a notice with the

FERC noting that the following Participant was suspended from the New England Markets on the date indicated (at 8:30 a.m.) due to a Payment Default:

Date of Suspension/FERC Notice

Participant Name Date Reinstated

Dec 27/29 Plant-E Corp. Dec 29

Suspension notices are for the FERC’s information only and are not docketed or noticed for public comment.


Questions concerning any of the ERO Reliability Standards or related rule-making proceedings or filings can be directed to Pat Gerity (860-275-0533; [email protected]).

• FERC Staff Report on CIP v5 Reliability Standards Audits (not docketed) On October 6, 2017, FERC Staff issued a report offering recommendations to help those subject to the

Critical Infrastructure Protection (“CIP”) Reliability Standards to assess their risk, compliance with those standards and their overall cyber security. The report describes the lessons learned from FERC-led audits completed in fiscal years 2016 and 2017, including insights into the cyber security and CIP compliance issues encountered by the audited entities. Among staff’s recommendations:

• Ensure that all shared facility categorizations are coordinated between the owners of the shared facility through clearly defined and documented responsibilities for CIP reliability standards compliance;

• Ensure that policies and testing procedures for all electronic communications protocols are afforded the same rigor; and

• For each remote cyber asset conducting Interactive Remote Access, disable all other network access outside of the connection to the bulk electric system cyber system that is being remotely accessed, unless there is a documented business or operational need.

• NOPR: Cyber Security Incident Reporting Reliability Standards (RM18-2) On December 21, 2017 the FERC issued a NOPR proposing to direct NERC to develop and submit

modifications to the Critical Infrastructure Protection (“CIP”) Reliability Standards to improve the reporting of Cyber Security Incidents, including incidents that might facilitate subsequent efforts to harm the reliable operation of the bulk electric system (e.g. (incidents that compromise, or attempt to compromise, a responsible entity’s Electronic Security Perimeter (“ESP”) or associated Electronic Access Control or Monitoring Systems (“EACMS”)).46 The mandatory reporting requirements are intended to improve awareness of existing and future cyber security threats and potential vulnerabilities. The reports would continue to go to the Electricity Information Sharing and Analysis Center (“E-ISAC”), but reports would also go to the Industrial Control Systems Cyber Emergency Response Team (“ICS-CERT”), with an annual, public, and anonymized summary of the reports. Comments on the Cyber Security Incident Reporting NOPR are due on or before February 26, 2018.47

46Cyber Security Incident Reporting Reliability Standards, 161 FERC ¶ 61,291 (Dec. 21, 2017) (“Cyber Security Incident Reporting

NOPR”).

47 The Cyber Security Incident Reporting NOPR was published in the Fed. Reg. on Dec. 28, 2017 (Vol. 82, No. 248) pp. 61,499-

61,505.




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• Revised Reliability Standards: CIP-005-6, CIP-010-3, CIP-013-1 (RM17-13) On September 26, 2017, NERC filed revised CIP Reliability Standards -- CIP-005-6 (Cyber Security –

Electronic Security Perimeter(s)), CIP-010-3 (Cyber Security – Configuration Change Management and Vulnerability Assessments) and CIP-013-1 (Cyber Security – Supply Chain Risk Management) (together, the “Supply Chain Cybersecurity Risk Management Changes”). In addition, the FERC proposed to approve the associated VRFs, VSLs, implementation plans, effective dates, and retirements of the applicable currently-effective versions of the Standards immediately prior to the effective dates of the new Standards. The Supply Chain Cybersecurity Risk Management Changes are designed to further mitigate cybersecurity risks associated with the supply chain for BES Cyber Systems, consistent with Order 829. NERC proposes that the Supply Chain Cybersecurity Risk Management Changes become effective on the first day of the first calendar quarter that is 18 calendar months after the effective date of the Commission’s order approving the Changes. As of the date of this Report, the Supply Chain Cybersecurity Risk Management Changes have not been noticed for public comment.

• NOPR: Revised Reliability Standards: EOP-004-4, EOP-005-3, EOP-006-3, EOP-008-2 (RM17-12) On September 20, 2017, the FERC issued a NOPR proposing to approve Emergency Preparedness and

Operations (“EOP”) Reliability Standards EOP-004-4 (Event Reporting), EOP-005-3 (System Restoration from Blackstart Resources), EOP-006-3 (System Restoration Coordination), and EOP-008-2 (Loss of Control Center Functionality) (together, the “EOP Changes”).48 In addition, the FERC proposed to approve the associated VRFs, VSLs, implementation plans, effective dates, and retirements of the currently-effective versions of the Standards immediately prior to the effective dates of the new Standards. The EOP Changes are designed to incorporate several recommendations resulting from a periodic review of the Standards, changes to eliminate inaccurate or duplicate reporting of events identified in the Department of Energy’s (“DOE”) Electric Emergency Incident and Disturbance Report (OE-417) and Attachment 1 to EOP-004, and to improve the Standards by enhancing the requirements for emergency operations, including the communication and coordination amongst reporting entities. Comments on the EOP NOPR were due on or before November 27, 201749 and were filed by NERC, EEI, and Magnum CAES. The EOP NOPR is pending before the FERC.

• NOPR: Revised Reliability Standard: CIP-003-7 (RM17-11) On October 19, 2017 the FERC issued a NOPR proposing to approve changes to Reliability Standard CIP-

003 (Cyber Security - Security Management Controls), its associated implementation plan, VRFs, VSLs, and revised NERC Glossary definitions of “Removable Media” and “Transient Cyber Asset”, and the retirement of the currently-effective version of CIP-003 and the NERC Glossary definitions of “Low Impact External Routable Connectivity” and “Low Impact BES Cyber System Electronic Access Point” (“CIP-003 Changes”).50 The CIP-003 Changes (i) clarify the electronic access control requirements applicable to low impact BES Cyber Systems; (ii) add requirements related to the protection of transient electronic devices used for low impact BES Cyber Systems (e.g., thumb drives, laptop computers, and other portable devices frequently connected to and disconnected from systems); and (iii) require Responsible Entities to have a documented cyber security policy related to declaring and responding to CIP Exceptional Circumstances for low impact BES Cyber Systems. In addition, the FERC proposes to direct NERC to develop certain modifications to the NERC Reliability Standards to provide clear, objective criteria for electronic access controls for low impact BES Cyber Systems; and address the need to mitigate the risk of malicious code that could result from third-party transient electronic devices. The proposed implementation plan provides that the CIP-003-Changes become effective on the first day of the first calendar quarter that is 18 calendar months after the effective date of the FERC’s order approving the CIP-003

48Emergency Preparedness and Ops. Rel. Standards, 160 FERC ¶ 61,072 (Sep. 20, 2017) (“EOP NOPR”).

49 The EOP NOPR was published in the Fed. Reg. on Sep. 26, 2017 (Vol. 82, No. 185) pp. 44,746-44,750.

50Rev. Critical Infrastructure Protection Rel. Standard CIP-003-7 – Cyber Security – Security Management Controls, 161 FERC ¶

61,047 (Oct. 19, 2017) (“CIP-003-7 NOPR”).



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Changes. Comments on the CIP-003-7 NOPR were due on or before December 26, 2017,51 and were filed by NERC, ELCON, TAPS, and Trade Associations52 (each urging the FERC to approve the CIP-003 Changes without directives or conditions) and by an individual, Jonathan Applebaum, who submitted comments limited to, and contesting the sufficiency of, the proposed electronic access controls requirement. This matter is pending before the FERC.

• NOPR: New Reliability Standards: PRC-027-1 and PER-006-1 (RM16-22) On November 16, 2017 the FERC issued a NOPR proposing to (i) two new Reliability Standards -- PRC-

027-1 (Coordination of Protection Systems for Performance During Faults) and PER-006-1 (Specific Training for Personnel), (ii) associated Glossary definitions, (iii) an implementation plan, (iv) VRFs and VSLs, and (v) the retirement of PRC-001-1.1(ii) (together, the “Protection System Changes”). In addition, the FERC proposes to direct NERC to develop certain modifications to PRC-027-1. NERC stated that the purpose of the Protection System Changes is to: (1) maintain the coordination of Protection Systems installed to detect and isolate Faults on Bulk Electric System (“BES”) Elements, such that those Protection Systems operate in the intended sequence during Faults; and (2) require registered entities to provide training to their relevant personnel on Protection Systems and Remedial Action Schemes (“RAS”) to help ensure that the BES is reliably operated. NERC requested that the new Standards and definitions become effective on the first day of the first calendar quarter that is 24 months following the effective date of the FERC’s order approving the Standards. Comments on the Protection System Changes NOPR are due on or before January 22, 2018.53

• NOPR: Revised Reliability Standard: MOD-001-2 (RM14-7) The ATC NOPR remains pending before the FERC. As previously reported, the FERC’s June 19, 2014,

NOPR54 proposed to approve changes to MOD-001-2 (Modeling, Data, and Analysis - Available Transmission System Capability) to replace, consolidate and improve upon the Existing MOD Standards in addressing the reliability issues associated with determinations of Available Transfer Capability (“ATC”) and Available Flowgate Capability (“AFC”). MOD-001-2 will replace the six Existing MOD Standards55 to exclusively focus on the reliability aspects of ATC and AFC determinations. NERC requested that the revised MOD Standard be approved, and the Existing MOD Standards be retired, effective on the first day of the first calendar quarter that is 18 months after the date that the proposed Reliability Standard is approved by the FERC. NERC explained that the implementation period is intended to provide NAESB sufficient time to include in its WEQ Standards, prior to MOD-001-2’s effective date, those elements from the Existing MOD Standards, if any, that relate to commercial or business practices and are not included in proposed MOD-001-2. The FERC sought comment from NAESB and others whether 18 months would provide adequate time for NAESB to develop related business practices associated with ATC calculations or whether additional time may be appropriate to better assure synchronization of the effective dates for the proposed Reliability Standard and related NAESB practices. The FERC also sought further elaboration on specific actions NERC could take to assure synchronization of the effective dates. Comments on this NOPR were due August 25, 2014,56 and were filed by NERC, Bonneville, Duke, MISO, and NAESB. On December 19, 2014, NAESB supplemented its comments with a report on its efforts to develop WEQ Business Practice Standards that will support and coordinate with the MOD Standards proposed in this proceeding. NASEB issued a report on September 25, 2015, informing the FERC that the NAESB standards development process has been completed and NAESB will file the new suite of business practice standards as

51 The CIP-007-3 NOPR was published in the Fed. Reg. on Oct. 26, 2017 (Vol. 82, No. 206) pp. 49,541-49,549.

52 “Trade Associations” are the American Public Power Association (“APPA”), Edison Electric Institute (“EEI”) and the National

Rural Electric Cooperative Association (“NRECA”).

53 The Protection System Changes NOPR was published in the Fed. Reg. on Nov. 22, 2017 (Vol. 82, No. 224) pp. 55,535-55,541.

54Modeling, Data, and Analysis Rel. Standards, 147 FERC ¶ 61,208 (June 19, 2014) (“ATC NOPR”).

55 The 6 existing MOD Standards to be replaced by MOD-001-2 are: MOD-001-1, MOD-004-1, MOD-008-1, MOD-028-2, MOD-

029-1a and MOD-030-2.

56 The MOD-001-2 NOPR was published in the Fed. Reg. on June 26, 2014, (Vol. 79, No. 123) pp. 36,269-36,273.



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part of Version 003.1 of the NAESB WEQ Business Practice Standards in October 2015. As noted above, the ATC NOPR remains pending before the FERC.

• Rules of Procedure Changes (RR18-1) On November 21, 2017, NERC filed for approval revisions to Appendix 3D (Registered Ballot Body

Criteria) of the NERC Rules of Procedure (“ROP”). NERC stated that the purpose of the proposed revisions is to help ensure that the votes of Independent System Operators (“ISOs”) and Regional Transmission Organizations (“RTOs”) are appropriately represented in Segment 2 of NERC’s registered ballot body for voting on Reliability Standards. Specifically, the revisions limit participation in “Segment 2” to RTO/ISOs exclusively, excluding other individuals and entities who may be consultants or vendors to RTO/ISOs from participating in that Segment. NERC requested that the proposed revisions be made effective upon FERC approval. Comments on this filing were due on or before December 12, 2017; none were filed. Dominion filed a doc-less intervention. This matter is pending before the FERC.

• Rules of Procedure Changes (RR17-6) On June 26, 2017, NERC filed for approval revisions to Sections 600 (Personnel Certification Program)

and 900 (Training and Education) of the NERC Rules of Procedure (“ROP”). The purpose of the revisions is to (i) clarify the scope of the Personnel Certification Program, the Training and Education Program and the Continuing Education Program; and (ii) streamline and align the language of the ROP with current practices of those programs. NERC stated that the changes are part of its first comprehensive review to modernize and align the language of the ROP with current NERC practices. NERC requested that the proposed revisions be made effective upon FERC approval. Comments on this filing were due on or before July 17, 2017 and were filed jointly by the Alberta Electric System Operator (“AESO”), The California Independent System Operator (“CAISO”), The Independent Electricity System Operator (“IESO”), ISO-NE and PJM (“System Operators”). System Operators, while agreeing that changes to Sections 600 and 900 are needed, nevertheless disagreed with the proposed changes as written and the rationale for making those changes in the first instance. On October 17, NERC answered System Operators’ comments. This matter remains pending before the FERC.

XI. Misc. - of Regional Interest

• 203 Application: PSNH/HSE Hydro NE (EC18-42) On December 28, 2017, PSNH and HSE Hydro NE AC, LLC (“HSE Hydro NE”)57 requested authorization for

a proposed transaction pursuant to which HSE Hydro NE will acquire PSNH’s portfolio of hydroelectric generation assets (the “PSNH Hydro Transaction”).58 Applicants requested an order authorizing the PSNH Hydro Transaction on or before February 23, 2018. Comments on the application are due on or before January 18, 2018.

• 203 Application: Dynegy/Vistra (EC18-23) On November 22, Dynegy and Vistra Energy Corp. (“Vistra”) requested authorization for a proposed

transaction pursuant to which Dynegy will merge with and into Vistra, with Vistra being the surviving corporation (the “Vistra Transaction”). Applicants requested an order authorizing the Vistra Transaction on or before March 15, 2018. Comments on the application are due on or before January 22, 2018.

57 HSE Hydro NE is a Related Person to Generation Sector Group Seat members Nautilus Hydro and Pawtucket Power.

58 PSNH’s hydroelectric generation portfolio (61.8 MW) includes the following facilities: Smith (15.78 MW); Amoskeag (17.5

MW); Garvins Falls/Hooksett (7.09 MW); Ayers Island (8.94 MW); Eastman Falls (6.1 MW); Jackman (3.54 MW); Gorham (1.68 MW); Canaan (1.17 MW).



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• 203 Application: PSNH/Granite Shore (EC18-12) On December 27, the FERC authorized the acquisition by Granite Shore Power LLC (“Granite Shore”)59 of

a portfolio of PSNH generation assets60 (the “Granite Shore Transaction”).61 Among other conditions, the order required notice within 10 days of the consummation of the transaction, which is expected to occur before the end of 2017. Subject to that notice, this proceeding will be concluded.

• 203 Application: Calpine/ECP (EC17-182) On September 15, Calpine Corporation (“Calpine”) requested authorization for a proposed transaction

pursuant to which it will become an indirect, wholly-controlled subsidiary of ECP Control Co, LLC (“ECP”) (the “Calpine/ECP Transaction”). Applicants requested an order authorizing the Calpine/ECP Transaction on or before January 15, 2018. Comments on the application were due on or before November 14, 2017. A protest was filed by Public Citizen, which asserted that, because the application failed to include Dynegy’s merchant generation assets in the market power analysis (in which it believes Capital Partners has a significant financial interest), the application was incomplete. Calpine answered the Public Citizen protest, refuting its assertions and arguments. Public Citizen answered Calpine’s answer, again asserting that the application be considered incomplete until ECP fully divests all Dynegy ownership or redoes the Competitive Analysis Screen to include ECP’s ownership of Dynegy. This matter is pending before the FERC.

• 203 Application: GenOn Reorganization (EC17-152) On October 31, the FERC approved certain conversions of GenOn notes into common equity of, and

corporate structure changes that will result in, a “reorganized GenOn”.62 Reorganized GenOn will emerge as a result of a plan of reorganization to be confirmed by the United States Bankruptcy Court for the Southern District of Texas in connection with GenOn’s Chapter 11 restructuring (the “Restructuring”). As a result of the Restructuring, Reorganized GenOn will likely not be a subsidiary of, and GenOn Energy Management will thus likely no longer be a Related Person to, NRG. Among other conditions, the order required notice within 10 days of the consummation of the transaction. Subject to that notice, this proceeding will be concluded.

• 203 Application: Green Mountain Power/ENEL Hydros (EC17-76) On May 9, the FERC authorized GMP’s acquisition of the following small hydroelectric generation

facilities (each a QF, collectively 8.39 MW of total generating capacity) from subsidiaries of Enel Green Power North America, Inc.: Hoague-Sprague, Kelley’s Falls, Lower Valley, Glen, Rollinsford, South Berwick, Somersworth, and Woodsville.63 Among other conditions, the order required notice within 10 days of the consummation of the transaction, which as of date of this Report has not been filed. Subject to that notice, this proceeding will be concluded.

• 203 Application: WMECO /NSTAR Merger (EC17-62) On March 2, 2017, the FERC authorized Eversource’s internal reorganization under which Western

Massachusetts Electric Company (“WMECO”) will merge with and into NSTAR Electric Company (“NSTAR”), with NSTAR as the surviving entity.64 Applicants committed to hold harmless transmission and wholesale customers from transaction-related costs for five years to the extent that such costs exceed savings related to the merger. On September 22, 2017, Eversource submitted an informational filing notifying the FERC that, while there will be

59 Granite Shore is a Related Person to Supplier Sector members Castleton Commodities Merchant Trading LP, Rensselaer

Generating LLC, and Roseton Generating LLC.

60 PSNH’s generation portfolio (1,130 MW) includes the following facilities: Merrimack, Schiller, Newington, White Lake, and

Lost Nation.

61Pub. Service Co. of New Hampshire, Granite Shore Power LLC, 161 FERC ¶ 62,231 (Dec. 27, 2017).

62GenOn Energy Inc., et al., 161 FERC ¶ 62,063 (Oct. 31, 2017).

63Green Mountain Power Corp., 159 FERC ¶ 62,144 (May 9, 2017).

64NSTAR Elec. Co. and W. Mass. Elec. Co., 158 FERC ¶ 62,155 (Mar. 2, 2017) (“NSTAR/WMECO Merger Order”).



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no rate changes filed to accomplish the merger, NSTAR will temporarily keep separate books and records for transmission service and ratemaking purposes, and will continue to provide transmission service and charge customers rates as if the transmission assets were owned by legally separate entities, until it makes an application with the FERC to consolidate rates. Until that time, NSTAR Electric will use “NSTAR Electric (East)” and “NSTAR Electric (West)” to refer to the transmission services and rates previously provided separately by NSTAR Electric and WMECO, respectively. On January 3, Eversource filed a notice reporting that the merger occurred on December 31, 2017. Reporting on this matter is thus concluded.

• MOPR-Related Proceedings (PJM, NYISO) (EL16-49; EL13-62) In two proceedings which, unless narrowly limited solely to the unique facts of the directly

applicable markets (PJM in EL16-49; NYISO in EL13-62), could impact the New England market through FERC jurisdictional or other determinations, NEPOOL filed limited comments requesting that any Commission action or decision be limited narrowly to the facts and circumstances as presented in the applicable market. NEPOOL urged that any changes that may be ordered by the Commission in the proceedings not circumscribe the results of NEPOOL’s stakeholder process or predetermine the outcome of that process through dicta or a ruling concerning different markets with different history and different rules. NEPOOL’s comments were filed on January 24 in the NYISO proceeding; January 30 in the PJM proceeding, and are pending before the FERC. Since the last Report, EPSA filed motions to lodge information in each proceeding. In the PJM proceeding, EPSA moved to lodge a July 14, 2017 Memorandum Opinion and Order of the United States District Court for the Northern District of Illinois, Eastern Division, which dismissed challenges to the zero emissions credits (“ZECs”) legislation enacted by the State of Illinois. In the NYISO proceeding, in a substantively similar motion, EPSA moved to lodge a Memorandum and Order of the New York District Court dismissing challenges to the ZECs program implemented by the NYPSC. In each case, EPSA reiterated its position that unless addressed, the ZEC programs will adversely impact the respective markets. Answers to the EPSA motions to lodge were filed by Exelon and the NYPSC in the NYISO Proceeding and by Exelon, First Energy, the Load Group, NRECA, Talen Companies, and the Illinois Commerce Commission in the PJM Proceeding. These proceedings remain pending before the FERC. If you have any questions concerning these proceedings, please contact Dave Doot (860-275-0102; [email protected]) or Sebastian Lombardi (860-275-0663; [email protected]).

• LGIA: Emera Maine/Penobscot Energy Recovery Co (ER18-505) On December 21, 2017, Emera Maine filed a fully executed, non-conforming LGIA with Penobscot

Energy Recovery Company (“Penobscot”). The LGIA would establish the interconnection of Penobscot’s solid 25 MW waste-fired generating facility (Line 247) as a direct assignment facility (possible because its radial in nature and serves a single customer) and thereby support Penobscot's access to New England Market upon expiration of its long-time PPA with Emera Maine (through a resulting lower monthly charge). A March 1, 2018 effective date was requested. Comments on this filing are due on or before January 11, 2018. If you have any questions concerning this matter, please contact Pat Gerity ([email protected]; 860-275-0533).

• Third Supplement to Lease Agreement: UI/CT DOT (ER18-454) On December 14, 2017, UI filed an amendment to the Lease Agreement between it and the

Connecticut Department of Transportation (“CT DOT”), providing for the recovery by UI of costs UI has incurred and will incur in connection with certain Direct Assignment Facilities (“DAF”) necessary to facilitate the purchase by Metro-North Commuter Railroad Company (“Metro-North”) of additional electric energy to power new commuter rail cars that Metro-North plans to deploy on its New Haven Line. A December 15, 2017 effective date was requested. Comments on this filing are due on or before January 4, 2018. If you have any questions concerning this matter, please contact Pat Gerity ([email protected]; 860-275-0533).







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• Anbaric’s Ocean Grid Project: Transmission Rights at Negotiated Rates (ER18-435) On December 13, 2017, Anbaric Development Partners (“Anbaric”) requested FERC authorization to

sell transmission rights at negotiated rates on its “Ocean Grid Project”, an integrated offshore transmission system that includes two 1,000 to 1,200 megawatt (“MW”) High-Voltage Direct Current (“HVDC”) transmission lines, each approximately 40 to 60 miles in length, with a total integrated system capacity of up to 2,400 MW, connecting Massachusetts off-shore wind generation to the transmission system in the Southeastern Massachusetts Load Zone (“SEMA”). Anbaric anticipates that the first phase of the Project (1,200 MW) will be in service by December 2021 and the second phase in service by 2024. Anbaric requested an order on its application on or before February 12, 2018. Comments on this filing were due on January 3, 2018; none were filed. A doc-less intervention was filed by Bay State Wind LLC. This matter is pending before the FERC. If you have any questions concerning this matter, please contact Pat Gerity ([email protected]; 860-275-0533).

• IA: NSTAR/Covanta SEMASS (ER18-424) On December 11, 2017, NSTAR filed a two-party IA between itself and Covanta SEMASS (“Covanta”)

to replace an October 31, 1985 Power Sale Agreement between the parties which expired on December 1, 2017 and to recognize that Covanta now uses the New England transmission system to market the output of its 80 MW Rochester, MA facility. Comments on this filing were due on or before January 2, 2018; none were filed. This matter is pending before the FERC. If you have any questions concerning this matter, please contact Pat Gerity ([email protected]; 860-275-0533).

• NEP/HQUS Phase I/II HVDC-TF Service Agreement (ER18-388) On December 5, NEP filed a new Phase I/II HVDC-TF Service Agreement with HQUS to allow the

continuation without interruption of service provided pursuant to an existing agreement between NEP and HQUS that conforms to the pro forma Phase I/II HVDC-TF Service Agreement set forth in Attachment A of Schedule 20A–Common to the ISO-NE OATT. The Agreement is being filed as “non-conforming” as it was unclear whether the FERC would deem conforming the provisions included in the Agreement that accommodate HQUS’ exercise of its right of first refusal to extend its transmission customer service rights beyond the five-year term of its currently effective Service Agreement with NEP pursuant to Schedule 20A (while taking into account the fact that NEP currently only has contractual rights allowing it to sell service over the Phase I/II HVDC-TF through October 31, 2020). A January 1, 2018 effective date was requested. Comments, if any, on this filing were due on or before December 26 and were filed by HQUS, which supported the filing and requested that the Service Agreement be accepted as filed. This matter is pending before the FERC. If you have any questions concerning this matter, please contact Pat Gerity ([email protected]; 860-275-0533).

• D&E Agreement Cancellation: NSTAR/Essential Power Newington (ER18-330) On November 27, NSTAR filed a notice of cancellation of the Design and Engineering Agreement

(“D&E Agreement”) between NSTAR and Essential Power Newington (designated as service agreement IA-NSTAR-34). The D&E Agreement set forth the terms and conditions under which NSTAR undertook certain design and engineering activities on its transmission system65 in connection with Essential Power Newington’s FCA11 New Capacity Qualification Determination Notification. With the work completed, the D&E Agreement is now terminated. A November 27, 2017 effective date was requested. Comments, if any, on this filing were due on or before December 18; none were filed. This matter is pending before the FERC. If you have any questions concerning this matter, please contact Pat Gerity ([email protected]; 860-275-0533).

65 Specifically, NSTAR has agreed to make changes to the Zone 2 timer on both primary (P1) and backup (P2) relays at its Mystic

Substation that are associated with NSTAR Line 423-515.







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• IA: CL&P/Woods Hill Solar (ER18-316) On November 20, 2017, Eversource, on behalf of CL&P, filed a two-party IA between CL&P and

Woods Hill Solar to govern the interconnection of a 20 MW photovoltaic (“PV”) generating facility to be located in Pomfret, CT. A November 30, 2017 effective date was requested. Comments on this filing were due on or before December 11, 2017; none were filed. This matter is pending before the FERC. If you have any questions concerning this matter, please contact Pat Gerity ([email protected]; 860-275-0533).

• D&E Agreement: Pootatuck Ring Bus Expansion (ER18-111) On December 7, the FERC accepted the D&E Agreement between The United Illuminating Company

(“UI”) and Eversource for the planned Pootatuck Substation Ring Bus Expansion. The “Ring Bus Expansion” (relocation of the existing line structure and reconfiguration of the Pootatuck Substation into a four-breaker “ring” bus expansion ) is designed to address conditions created under certain contingencies in which UI transmission loads could be subject to overloads or voltage collapse conditions. The D&E Agreement was accepted effective as of October 20, 2017, as requested. Unless the December 7 order is challenged, this proceeding will be concluded. If you have any questions concerning this matter, please contact Pat Gerity ([email protected]; 860-275-0533).

• IA: PSNH/Pontook (ER17-2449) On December 13, the FERC accepted the two-party IA between PSNH and Pontook for the continued

provision of interconnection service to Pontook’s existing 3-unit, 9.6 MW hydro-electric facility located on the Androscoggin River in Dummer, New Hampshire. As previously reported, the facility has been connected to PSNH distribution system since 1986, Pontook makes use of PSNH’s distribution system and the New England transmission system to market the output of the facility, and the IA replaces a 1985 Agreement whose initial 3-year term has expired. Because there was no modification to the facility or to the interconnection facilities, a three-way IA between PSNH, Pontook and ISO-NE under Schedule 23 of the ISO-NE OATT was not required. The IA was accepted effective as of December 16, 2016, as requested. Unless the December 13 order is challenged, this proceeding will be concluded. If you have any questions concerning this matter, please contact Pat Gerity ([email protected]; 860-275-0533).

• FERC Enforcement Action: Order of Non-Public, Formal Investigation (IN15-10) MISO Zone 4 Planning Resource Auction Offers. On October 1, 2015, the FERC issued an order

authorizing Enforcement to conduct a non-public, formal investigation, with subpoena authority, regarding violations of FERC’s regulations, including its prohibition against electric energy market manipulation, that may have occurred in connection with, or related to, MISO’s April 2015 Planning Resource Auction for the 2015/16 power year.

Unlike a staff NOV, a FERC order converting an informal, non-public investigation to a formal, non-public investigation does not indicate that the FERC has determined that any entity has engaged in market manipulation or otherwise violated any FERC order, rule, or regulation. It does, however, give OE’s Director, and employees designated by the Director, the authority to administer oaths and affirmations, subpoena witnesses, compel their attendance and testimony, take evidence, compel the filing of special reports and responses to interrogatories, gather information, and require the production of any books, papers, correspondence, memoranda, contracts, agreements, or other records.

• FERC Audit of ISO-NE (PA16-6) The FERC’s audit of ISO-NE docketed in this proceeding is on-going. As previously reported, the

FERC informed ISO-NE on November 24, 2015 that it would evaluate ISO-NE’s compliance with: (1) the transmission provider obligations described in the Tariff, (2) Order 1000 as it relates to transmission planning and expansion, and interregional coordination, (3) accounting requirements of the Uniform System of Accounts under 18 C.F.R. Part 101, (4) financial reporting requirements under 18 C.F.R. Part 141; and (5)






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record retention requirements under 18 CFR Part 125. The FERC indicated that the audit will cover the July 10, 2013 period through the present.

XII. Misc. - Administrative & Rulemaking Proceedings

• State Policies & Wholesale Markets Operated by ISO-NE, NYISO, PJM (AD17-11) As previously reported, the FERC held a 2-day technical conference (on May 1-2) to foster further

discussion regarding the development of regional solutions in the Eastern RTOs/ISOs that reconcile the competitive market framework with the increasing interest by states to support particular resources or resource attributes. FERC staff sought to “discuss long-term expectations regarding the relative roles of wholesale markets and state policies in the Eastern RTOs/ISOs in shaping the quantity and composition of resources needed to cost-effectively meet future reliability and operational needs”. A more detailed summary of the technical conference was circulated with the last Report. Pre-conference comments from the conference’s speakers, panelists and other interested parties are available in the FERC’s eLibrary and through the tech conference’s calendar entry. Those interested were invited to submit post-conference comments on or before June 22. Comments were received from over 80 parties, and were briefly summarized at the Summer Meeting. Reply comments, not exceeding 10 pages, were filed by over 30 parties. This matter remains pending before the FERC.

• NOI: FERC's Policy for Recovery of Income Tax Costs & ROE Policies (PL17-1) On December 15, 2016, the FERC issued a notice of inquiry (“NOI”) seeking comments regarding how to

address any double recovery resulting from the FERC’s current income tax allowance and ROE policies.66 The NOI followed the D.C. Circuit’s United Airlines67 holding that the FERC failed to demonstrate that there is no double recovery of taxes for a partnership pipeline as a result of the income tax allowance and ROE determined pursuant to the DCF methodology, and remanding the decisions to the FERC to develop a mechanism “for which the Commission can demonstrate that there is no double recovery” of partnership income tax costs”.68

Comments and reply comments were submitted by over 25 and 18 parties, respectively. Since the last Report, on January 2, 2018, R. Gordon Gooch filed a motion requesting that the FERC compel all pass-through entities to reduce their claims for income tax allowance in rates, lowering rates as necessary to make their rates “just and reasonable” in response to the passage and signature into law of the “Tax Cut and Jobs Act” (Public Law No. 115-97). This matter remains pending before the FERC.

• DOE-Initiated Proposal: Grid Reliability & Resilience Pricing Rule (RM18-1) On September 28, exercising rarely-used authority under §403(a) of the Department of Energy (“DOE”)

Organization Act, Secretary of Energy Rick Perry sent to the FERC a proposal in the form of a NOPR that would, if adopted by the FERC, require RTO/ISOs to develop and implement market rules for the full recovery of costs and a fair rate of return for “eligible units” that (i) are able to provide essential energy and ancillary reliability services, (ii) have a 90-day fuel supply on site in the event of supply disruptions caused by emergencies, extreme weather, or natural or man-made disasters, (iii) are compliant with all applicable environmental regulations, and (iv) are not subject to cost-of-service rate regulation by any State or local authority. Secretary Perry established an aggressive 60-day timeframe for FERC action on the NOPR, with the aim of having new compensation mechanisms in place by winter.

On October 2, the FERC issued a notice inviting initial comments on the DOE proposal to be submitted by October 23, with reply comments due November 7. On October 4, the Director of the Office of Energy Policy and Innovation issued a list of questions to be addressed (to assist FERC Staff in its understanding of the

66Inquiry Regarding the FERC’s Policy for Recovery of Income Tax Costs, 157 FERC ¶ 61,210 (Dec. 15, 2017).

67United Airlines Inc., et al. v. FERC, 827 F.3d 122, 134, 136 (D.C. Cir. 2016) (“United Airlines”).

68Id. at 137.



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implications of the proposed rule) related to the need for reform, eligibility, implementation, rates, and other. A number of requests to extend the proposed deadlines were filed, but denied.

More than 450 comments were submitted by October 23 in response to the DOE NOPR. Those filings raise and discuss an exceptionally broad spectrum of process, legal, and substantive arguments. NEPOOL’s comments made the following three requests of FERC in considering its response to the DOE NOPR: (1) if FERC is inclined to issue a rule in response to the DOE NOPR, FERC should provide adequate time and process for meaningful stakeholder consideration and input on a FERC proposed rule before finalizing that rule; (2) if FERC concludes that changes to organized markets are needed, FERC should not mandate a single solution, but instead should allow sufficient flexibility, both procedurally and substantively, for each region with an organized market to address the concerns raised in the DOE NOPR with reference to the specific and unique circumstances of that region; and (3) FERC should ensure that there is adequate time for compliance with any final rule that might apply to New England so that New England can follow its FERC-approved stakeholder process in designing and finalizing any such compliance. A summary of the initial comments filed was circulated under separate cover and can be found with the posted materials for the November 3 meeting. Reply comments were due November 7 and were filed by over 100 parties, including ISO-NE. On November 20, NEPOOL filed a brief response to arguments made in certain reply comments, requesting that the FERC (i) reject any arguments that a one-size-fits-all solution should be implemented, without following applicable stakeholder processes, in response to the DOE NOPR, and (ii) respect regional differences and priorities, and to provide flexibility, both procedurally and substantively, for each region to satisfy its unique needs using its stakeholder processes in a time frame that allows for full and informed consideration of the market changes and is compatible with its priorities.

On December 7, FERC Chairman McIntyre requested a 30-day extension of time for FERC action on the DOE NOPR. On December 8, DOE Secretary Perry granted that extension, to January 11, 2018. Since the last Report, supplemental comments, information and answers were filed by Foundation for Resilient Societies (“FRS”), Global Energy Institute, Murray Energy, and certain public interest organizations and individuals. This matter is pending FERC action.

• NOPR: LGIA/LGIP Reforms (RM17-8) As previously reported, the FERC issued a NOPR69 on December 15, 2016 proposing reforms

designed to improve certainty,70 promote more informed interconnection,71 and enhance interconnection

69Reform of Generator Interconnection Procedures and Agreements, 157 FERC ¶ 61,212 (Dec. 15, 2016) (“LGIP/LGIA Reforms

NOPR”). The LGIP/LGIA Reforms NOPR was published in the Fed. Reg. on Jan. 13, 2017 (Vol. 82, No. 9 pp. 4,464-4,501.

70 To accomplish this goal, the FERC proposes to: (1) revise the pro forma LGIP to require transmission providers that conduct

cluster studies to move toward a scheduled, periodic restudy process; (2) remove from the pro forma LGIA the limitation that interconnection customers may only exercise the option to build transmission provider’s interconnection facilities and standalone network upgrades if the transmission owner cannot meet the dates proposed by the interconnection customer; (3) modify the pro formaLGIA to require mutual agreement between the transmission owner and interconnection customer for the transmission owner to opt to initially self-fund the costs of the construction of network upgrades; and (4) require that the RTO/ISO establish dispute resolution procedures for interconnection disputes. The Commission also seeks comment on the extent to which a cap on the network upgrade costs for which interconnection customers are responsible can mitigate the potential for serial restudies without inappropriately shifting cost responsibility. Id. at P 6.

71 The FERC proposes to: (1) require transmission providers to outline and make public a method for determining contingent

facilities in their LGIPs and LGIAs based upon guiding principles in the Proposed Rule; (2) require transmission providers to list in their LGIPs and on their OASIS sites the specific study processes and assumptions for forming the networking models used for interconnection studies; (3) require congestion and curtailment information to be posted in one location on each transmission provider’s OASIS site; (4) revise the definition of “Generating Facility” in the pro forma LGIP and LGIA to explicitly include electric storage resources; and (5) create a system of reporting requirements for aggregate interconnection study performance. The FERC also seeks comment on proposals or additional steps that the Commission could take to improve the resolution of issues that arise when affected systems are impacted by a proposed interconnection. Id. at P 7.



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processes.72 Based, in part, on input received in response to AWEA’s petition for changes to the pro formaLGIP/LGIA, and the FERC’s May 13, 2016 technical conference to explore generator interconnection issues (as reported previously under Docket Nos. RM16-12; RM15-21), the FERC identified proposed reforms which it states could remedy potential shortcomings in the existing interconnection processes. The FERC also sought comment on whether any of its proposed reforms should be applied to the pro forma SGIP/SGIA.73

60 sets of comments on and answer to the LGIP/LGIA Reforms NOPR were submitted, including comments by: NEPOOL (approved at the April 7 Participants Committee meeting), ISO-NE, Avangrid, EDF Renewable, EDP Renewables, Eversource, Exelon, Invenergy, National Grid, NextEra, APPA/LPPC/NRECA, AWEA, EEI, ELCON, ESA, and Public Interest Organizations. This matter is pending before the FERC.

• NOPR: Fast-Start Pricing in RTO/ISO Markets (RM17-3) On December 21, 2017, the FERC withdrew74 its December 2016 Fast-Start Pricing NOPR.75 The

FERC stated that, following “further consideration and after review of the comments received in response to the [Fast-Start Pricing NOPR], it was “persuaded by comments that … argued for regional flexibility.”76

However, the FERC, which “continue[s] to believe that improved fast-start pricing practices have the potential to achieve the goals outlined in the NOPR,” decided to pursue the goals of the NOPR through section 206 actions involving NYISO, PJM, and SPP.77 (Many of the proposed requirements in the Fast-Start NOPR were already implemented in New England on March 1, 2017, pursuant to changes jointly filed by ISO-NE and NEPOOL, and accepted, in 2015, in Docket No. ER15-2716).

• NOPR: Uplift Cost Allocation and Transparency in RTO/ISO Markets (RM17-2) On January 19, 2017, the FERC issued a NOPR proposing to require each RTO and ISO that currently

allocates the costs of Real-Time uplift due to deviations to do so only to those market participants whose transactions are reasonably expected to have caused the real-time uplift costs.78 In addition, the FERC proposed to revise its regulations to enhance transparency by requiring that each RTO/ISO post uplift costs paid (dollars) and operator-initiated commitments (MWs) on its website; and define in its tariff its transmission constraint penalty factors, as well as the circumstances under which those penalty factors can set LMPs, and any procedure for changing those factors. Comments and reply comments on the Uplift/Transparency NOPR were filed by over 40 parties, including: ISO-NE, Brookfield, Calpine, DC Energy, Direct, Exelon, Potomac Economics, Saracen, EEI, APPA/NRECA, Appian Way Energy Partners, AWEA, ELCON, EPSA, Financial Marketers Coalition, and the IRC. This matter is pending before the FERC.

72 The FERC proposes to: (1) allow interconnection customers to limit their requested level of interconnection service below

their generating facility capacity; (2) require transmission providers to allow for provisional agreements so that interconnection customers can operate on a limited basis prior to completion of the full interconnection process; (3) require transmission providers to create a process for interconnection customers to utilize surplus interconnection service at existing interconnection points; (4) require transmission providers to set forth a separate procedure to allow transmission providers to assess and, if necessary, study an interconnection customer’s technology changes (e.g., incorporation of a newer turbine model) without a change to the interconnection customer’s queue position; and (5) require transmission providers to evaluate their methods for modeling electric storage resources for interconnection studies and report to the Commission why and how their existing practices are or are not sufficient. Id. at P 8.

73Id. at P 11.

74Fast-Start Pricing in Markets Operated by Regional Transmission Organizations and Independent System Operators, 161 FERC

¶ 61,293 (Dec. 21, 2017) (“Order Withdrawing NOPR”).

75Fast-Start Pricing in Markets Operated by Regional Transmission Organizations and Independent System Operators, 157 FERC

¶ 61,213 (Dec. 15, 2016) (“Fast-Start Pricing NOPR”).

76Order Withdrawing NOPR at P 4.

77Id.

78Uplift Cost Allocation and Transparency in Markets Operated by Regional Transmission Organizations and Independent

System Operators, 158 FERC ¶ 61,047 (Jan. 19, 2017) (“Uplift/Transparency NOPR”).



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• NOPR: Electric Storage Participation in RTO/ISO Markets (RM16-23; AD16-20) The FERC’s Storage NOPR remains pending. As previously reported, on November 23, 2016, the

FERC issued the Storage NOPR proposing to require each RTO and ISO to revise its tariff “to (1) establish a participation model consisting of market rules that, recognizing the physical and operational characteristics of electric storage resources, accommodates their participation in the organized wholesale electric markets and (2) define distributed energy resource aggregators as a type of market participant that can participate in the organized wholesale electric markets under the participation model that best accommodates the physical and operational characteristics of its distributed energy resource aggregation.”79 Comments on the Storage NOPR were filed by over 100 parties, including: NEPOOL, ISO-NE, APPA/ NRECA, Avangrid, AWEA, Brookfield, CT DEEP, CT PURA, Dominion, DTE, EEI, ELCON, EPSA, EPRI, ESA, Exelon, FirstLight, Genbright, Harvard Environmental Policy Initiative, IPKeys, MA DPU, MIT, MMWEC, NARUC, NERC, NESCOE, NextEra, NRG, SEIA, UCS. Since the last Report, supplemental comments were filed by the Advanced Energy Management Alliance. In addition, on September 22, a number of US Senators80 requested that this rulemaking proceed towards completion as quickly as possible. Chairman Chatterjee responded to each on October 5, noting that the comments received are being reviewed and relaying his personal commitment to address the issues raised in the NOPR as the rulemaking proceeds forward. This matter remains pending before the FERC.

• NOPR: Data Collection for Analytics & Surveillance and MBR Purposes (RM16-17) The FERC’s Data Collection NOPR remains pending. As previously reported, the FERC issued a July

21, 2016 NOPR, which superseded both its Connected Entity NOPR (RM15-23) and Ownership NOPR (RM16-3), proposing to collect certain data for analytics and surveillance purposes from market-based rate (“MBR”) sellers and entities trading virtual products or holding FTRs and to change certain aspects of the substance and format of information submitted for MBR purposes.81 The Data Collection NOPR presents substantial revisions from what the FERC proposed in the Connected Entity NOPR, and responds to the comments and concerns submitted by NEPOOL in that proceeding. Among other things, the changes proposed in the Data NOPR include: (i) a different set of filers; (ii) a reworked and substantially narrowed definition of Connected Entity; and (iii) a different submission process. With respect to the MBR program, the proposals include: (i) adopting certain changes to reduce and clarify the scope of ownership information that MBR sellers must provide; (ii) reducing the information required in asset appendices; and (iii) collecting currently-required MBR information and certain new information in a consolidated and streamlined manner. The FERC also proposes to eliminate MBR sellers’ corporate organizational chart submission requirement adopted in Order 816. Comments on the Data Collection NOPR were due on or before September 19, 201682 and were filed by over 30 parties, including: APPA, Avangrid, Brookfield, EPSA, Macquarie/DC Energy/Emera Energy Services, NextEra, and NRG.

• Order 833: Critical Energy/Electric Infrastructure Information (CEII) Procedures (RM16-15) Rehearing of Order 83383 remains pending. As previously reported, Order 833 amended FERC

regulations to implement provisions of the Fixing America’s Surface Transportation (“FAST”) Act that pertain to the designation, protection and sharing of Critical Electric Infrastructure Information (“CEII”) and amend other

79Electric Storage Participation in Markets Operated by Regional Transmission Orgs. and Indep. Sys. Operators, 157 FERC ¶

61,121 (Nov. 17, 2016) (“Storage NOPR”).

80 Senators Whitehouse (RI), Booker (NJ), Markey (MA), Wyden (OR), Warren (MA), and Sanders (VT).

81Data Collection for Analytics and Surveillance and Market-Based Rate Purposes, 156 FERC ¶ 61,045 (July 21, 2016) (“Data

Collection NOPR”).

82 The Data Collection NOPR was published in the Fed. Reg. on Aug. 4, 2016 (Vol. 81, No. 150 pp. 51,726-51,772.

83Regulations Implementing FAST Act Section 61003 – Critical Electric Infrastructure Security and Amending Critical Energy

Infrastructure Information; Availability of Certain North American Electric Reliability Corporation Databases to the Commission, Order No. 833, 157 FERC ¶ 61,123 (Nov. 17, 2016) (“Order 833”).



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regulations that pertain to CEII. The amended procedures will be referred to as the Critical Energy/Electric Infrastructure Information (CEII) procedures. Order 833 became effective February 21, 2017.84 On December 19, 2016, EEI requested rehearing of Order 833. The FERC issued a tolling order on January 17, 2017 affording it additional time to consider the EEI request for rehearing, which remains pending.

• NOPR: Primary Frequency Response - Essential Reliability Services and the Evolving Bulk-Power System (RM16-6) The Primary Frequency Response NOPR85 remains pending. The Primary Frequency Response NOPR,

issued on November 17, 2016, proposes to require all newly interconnecting large and small generating facilities, both synchronous and non-synchronous, to install and enable primary frequency response capability as a condition of interconnection. To implement these requirements, the Commission proposes to revise the pro forma LGIA and the pro forma SGIA. The Primary Frequency Response NOPR follows the FERC’s Frequency Response NOI86 from early 2016. Comments on the Primary Frequency Response NOPRwere filed by over 30 parties, including AWEA, EEI, ELCON, EPSA, ESA, First Solar, the IRC, NRECA, and UCS. Supplemental comments were filed by ELCON. On August 18, 2017, the FERC issued a request for supplemental comments related to whether and when electric storage resources should be required to provide primary frequency response, and the costs associated with primary frequency response capabilities for small generating facilities.87 Supplemental comments were filed by over 20 parties, including the AES Companies, NERC, Western Interconnection Advisory Body, Magnum CAES, NRECA, Arizona Public Service, Tri-State Generation, and North American Generator Forum, Independent Transmission Company (“ITC”), the IRC, NYTOs, SoCal Edison, San Diego Gas & Electric, and the Energy Storage Association (“ESA”).


For further information on any of the natural gas proceedings, please contact Joe Fagan (202-218-3901; [email protected]) or Jamie Blackburn (202-218-3905; [email protected]).

• Algonquin EDC Capacity Release Bidding Requirements Exemption Request (RP16-618) On March 31, 2016, the FERC conditionally accepted Algonquin tariff modifications and request for

waiver that provided an exemption from capacity release bidding requirements for certain types of firm transportation capacity releases by Electric Distribution Companies (“EDCs”) that are participating in state-regulated electric reliability programs.88 As previously reported, Algonquin stated that the modifications were consistent with the FERC’s current policy of exempting releases pursuant to state-regulated retail access programs of natural gas local distribution companies (“LDCs”) from bidding requirements. Algonquin added that its proposal (i) supports the efforts of EDCs to increase the reliability of supply for natural gas-fired electric generation facilities in New England and to address high electricity prices during peak periods in New England and therefore is in the public interest; and (ii) furthers the FERC’s initiatives related to gas-electric coordination. On May 9, 2016, the FERC held a technical conference to examine “concerns raised regarding the basis and need for the waiver.” Initial comments were due May 31. Almost two dozen sets of initial comments were filed, raising numerous issues both in support and in opposition to the Algonquin proposal. Reply comments were due June 10, 2016 and were filed by Algonquin Gas Transmission, Sequent Energy Management, L.P. and

84Order 833 was published in the Fed. Reg. on Dec. 21, 2016 (Vol. 81, No. 245) pp. 93,732-93,753.

85Essential Reliability Services and the Evolving Bulk-Power System—Primary Frequency Response, 157 FERC ¶ 61,122 (Nov. 17,

2016) (“Primary Frequency Response NOPR”).

86Essential Reliability Services and the Evolving Bulk-Power System—Primary Frequency Response, 154 FERC ¶ 61,117 (Feb. 18,

2016 ) (“Frequency Response NOI”).

87 Notice of the Request for Supplemental Comments was published in the Fed. Reg. on Aug. 24, 2017 (Vol. 82, No. 163) pp.

40,081-40,085.

88Algonquin Gas Transmission, LLC, 154 FERC ¶ 61,269 (Mar. 31, 2016).





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Tenaska Marketing Ventures, Indicated Shippers, National Grid, Eversource, Repsol, Calpine, Exelon/NextEra, New England LDCs, CT PURA and the MA AG.

On August 31, 2016, the FERC issued an order in which it rejected Algonquin’s request for a waiver that would have exempted gas-fired generators from capacity release bidding requirements but accepted Algonquin’s proposal to exempt from bidding an EDC’s capacity release to an asset manager who is required to use the released capacity to carry out the EDC’s obligations under the state-regulated electric reliability program.89 The FERC explained that its capacity release regulations seek to balance the interests of the releasing shipper in releasing capacity to a replacement shipper of its choosing while still ensuring that allocative efficiency is enhanced by ensuring the capacity is used for its highest valued use.90 Algonquin’s proposal, whereby any gas-fired generator to whom EDCs release capacity would be a pre-arranged replacement shipper, failed to meet the standard of “improving the competitive structure of the natural gas industry” as formulated by the FERC in granting bidding exemptions for state-regulated retail access programs.91 Furthermore, the FERC found that exemption proponents had not shown why such a broad exemption was necessary in order for EDCs to have a sufficient ability to direct their capacity releases to natural gas-fired generators in order to accomplish the goal of increasing electric reliability.92 On September 30, 2016, ConEd and Orange & Rockland Utilities, Inc. (“O&R”) requested clarification of the Algonquin Order Following Technical Conference, asking the FERC to clarify certain aspects of its approval exempting from bidding an EDC’s capacity release to an asset manager. Algonquin Gas Transmission, National Grid Electric Distribution Companies, and Sequent Energy Management and Tenaska Marketing Ventures filed answers to the requests for clarification on October 17. Those requests are pending before the FERC.

On September 23, 2016, Algonquin submitted a compliance filing in response to the requirements of the Algonquin Order Following Technical Conference. Comments on that compliance were due on or before October 5, 2016; none were filed. The compliance filing remains pending before the FERC.

• Natural Gas-Related Enforcement Actions The FERC continues to closely monitor and enforce compliance with regulations governing open access

transportation on interstate natural gas pipelines:

BP (IN13-15). On July 11, 2016, the FERC issued Opinion 54993 affirming Judge Cintron’s August 13, 2015 Initial Decision finding that BP America Inc., BP Corporation North America Inc., BP America Production Company, and BP Energy Company (collectively, “BP”) violated Section 1c.1 of the Commission’s regulations (“Anti-Manipulation Rule”) and section 4A of the Natural Gas Act (“NGA”).94 Specifically, after extensive discovery and hearing procedures, Judge Cintron found that BP’s Texas team engaged in market manipulation by changing their trading patterns, between September 18, 2008 through the end of November 2008, in order to suppress next-day natural gas prices at the Houston Ship Channel (“HSC”) trading point in order to benefit correspondingly long position at the Henry Hub trading point. The FERC agreed, finding that the “record shows that BP’s trading practices during the Investigative Period were fraudulent or deceptive, undertaken with the requisite scienter, and carried out in connection with Commission-jurisdictional transactions.”95 Accordingly, the FERC assessed a $20.16 million civil penalty and required BP to disgorge $207,169 in “unjust profits it

89Algonquin Gas Transmission, LLC, 156 FERC ¶ 61,151 (Aug. 31, 2016) (“Algonquin Order Following Technical Conference”)

90Id. at P 27.

91Id. at P 34.

92Id. at P 35

93BP America Inc., et al., Opinion No. 549, 156 FERC ¶ 61,031 (July 11, 2016) (“BP Penalties Order”).

94BP America Inc., et al., 152 FERC ¶ 63,016 (Aug. 13, 2015) (“BP Initial Decision”).

95BP Penalties Order at P 3.



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received as a result of its manipulation of the Houston Ship Channel Gas Daily index.” The $20.16 million civil penalty was at the top of the FERC’s Penalty Guidelines range, reflecting increases for having had a prior adjudication within 5 years of the violation, and for BP’s violation of a FERC order within 5 years of the scheme. BP’s penalty was mitigated because it cooperated during the investigation, but BP received no deduction for its compliance program, or for self-reporting. The BP Penalties Order also denied BP’s request for rehearing of the order establishing a hearing in this proceeding.96 BP was directed to pay the civil penalty and disgorgement amount within 60 days of the BP Penalties Order. On August 10, 2016 BP requested rehearing of the BP Penalties Order. On September 8, the FERC issued a tolling order, affording it additional time to consider BP’s request for rehearing of the BP Penalties Order, which remains pending.

On September 7, 2016, BP submitted a motion for modification of the BP Penalties Order’sdisgorgement directive because it cannot comply with the disgorgement directive as ordered. BP explained that the entity to which disgorgement was to be directed, the Texas Low Income Home Energy Assistance Program (“LIHEAP”), is not set up to receive or disburse amounts received from any person other than the Texas Legislature. In response, on September 12, the FERC stayed the disgorgement directive (until an order on BP’s pending request for rehearing is issued), but indicated that interest will continue to accrue on unpaid monies during the pendency of the stay.97

Since the last Report, BP moved, on December 11, 217, to lodge, to reopen the proceeding, and to dismiss, or in the alternative, for reconsideration based on changes in the law it asserted are dispositive and that have occurred since BP filed its request for rehearing of the BP Penalties Order. FERC Staff asked for, and was granted, additional time, to January 25, 2018, to file its Answer to BP’s December 11 motion.

Total Gas & Power North America, Inc. et al. (IN12-17). On April 28, 2016, the FERC issued a show cause order98 in which it directed Total Gas & Power North America, Inc. (“TGPNA”) and its West Desk traders and supervisors, Therese Tran f/k/a Nguyen (“Tran”) and Aaron Hall (collectively, “Respondents”) to show cause why Respondents should not be found to have violated NGA Section 4A and the FERC’s Anti-Manipulation Rule through a scheme to manipulate the price of natural gas at four locations in the southwest United States between June 2009 and June 2012.99

The FERC also directed TGPNA to show cause why it should not be required to disgorge unjust profits of $9.18 million, plus interest; TGPNA, Tran and Hall to show cause why they should not be assessed civil penalties (TGPNA - $213.6 million; Hall - $1 million (jointly and severally with TGPNA); and Tran - $2 million (jointly and severally with TGPNA)). In addition, the FERC directed TGPNA’s parent company, Total, S.A. (“Total”), and TGPNA’s affiliate, Total Gas & Power, Ltd. (“TGPL”), to show cause why they should not be held liable for TGPNA’s, Hall’s, and Tran’s conduct, and be held jointly and severally liable for their disgorgement and civil penalties based on Total’s and TGPL’s significant control and authority over TGPNA’s daily operations. Respondents field their answer on July 12, 2016. OE Staff replied to Respondents’ answer on September 23,

96BP America Inc. et al., 147 FERC ¶ 61,130 (May 15, 2014) (“BP Hearing Order”), reh’g denied, 156 FERC ¶ 61,031 (July 11,

2016).

97BP America Inc. et al., 156 FERC ¶ 61,174 (Sep. 12, 2016) (“Order Staying BP Disgorgement”)

98Total Gas & Power North America, Inc., et al., 155 FERC ¶ 61,105 (Apr. 28, 2016) (“TGPNA Show Cause Order”).

99 The allegations giving rise to the Total Show Cause Order were laid out in a September 21, 2015 FERC Staff Notice of Alleged

Violations which summarized OE’s case against the Respondents. Staff determined that the Respondents violated section 4A of the Natural Gas Act and the Commission’s Anti-Manipulation Rule by devising and executing a scheme to manipulate the price of natural gas in the southwest United States between June 2009 and June 2012. Specifically, Staff alleged that the scheme involved making largely uneconomic trades for physical natural gas during bid-week designed to move indexed market prices in a way that benefited the company’s related positions. Staff alleged that the West Desk implemented the bid-week scheme on at least 38 occasions during the period of interest, and that Tran and Hall each implemented the scheme and supervised and directed other traders in implementing the scheme.



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2016. Respondents answered OE’s September 23 answer on January 17, 2017, and OE Staff responded to that answer on January 27, 2017. This matter remains pending before the FERC.

Staff Notices of Alleged Violations (IN__-___)

Rover. On July 13, 2017, the FERC issued a notice that Staff has preliminarily determined that, between February 2015 and September 2016, Rover Pipeline, LLC and Energy Transfer Partners, L.P. (collectively, “Rover”) violated Section 7 of the Natural Gas Act by failing to fully and forthrightly disclose all relevant information to the FERC in Rover’s application for a Certificate of Public Convenience and Necessity and attendant filings in Docket No. CP15-93. Staff alleges that Rover falsely promised it would avoid adverse effects to a historic resource that it was simultaneously working to purchase and destroy, and subsequently made several misstatements in its docketed responses to FERC questions about why it had purchased and demolished the resource.

Recall that Notices of Alleged Violations (“NoVs”) are issued only after the subject of an enforcement investigation has either responded, or had the opportunity to respond, to a preliminary findings letter detailing Staff’s conclusions regarding the subject’s conduct.100 NoVs are designed to increase the transparency of Staff’s nonpublic investigations conducted under Part 1b of its regulations. A NoV does not confer a right on third parties to intervene in the investigation or any other right with respect to the investigation.

• New England Pipeline Proceedings The following New England pipeline projects are currently under construction or before the FERC:

• Atlantic Bridge Project (CP16-9)

132,700 Dth/d of firm transportation to new and existing delivery points on the Algonquin system and 106,276 Dth/d of firm transportation service from Beverly, MA to various existing delivery points on the Maritimes & Northeast system.

6.3 miles of replacement pipeline along Algonquin in NY and CT; new 7,700-horsepower compressor station in Weymouth, MA; more horsepower at existing compressor stations in CT and NY.

Seven firm shippers: Heritage Gas Limited, Maine Natural Gas Company, NSTAR Gas Company d/b/a Eversource Energy, Exelon Generation Company, LLC (as assignee and asset manager of Summit Natural Gas of Maine), Irving Oil Terminal Operations, Inc., New England NG Supply Limited, and Norwich Public Utilities.

Certificate of public convenience and necessity granted Jan. 25, 2017.101

Certain facilities,102 providing 40,000 out of the project’s total capacity of 132,705 dekatherms per day of incremental firm transportation service, placed into service on November 1, 2017.103 Remaining Project capacity will be available when the remaining Project facilities are placed into service following Director of OEP authorization.

100See Enforcement of Statutes, Regulations, and Orders, 129 FERC ¶ 61,247 (Dec. 17, 2009), order on requests for reh’g and

clarification, 134 FERC ¶ 61,054 (Jan. 24, 2011).

101 Order Issuing Certificate and Authorizing Abandonment, Algonquin Gas Transmission LLC and Maritimes & Northeast

Pipeline, LLC, 158 FERC ¶ 61,061 (Jan. 25, 2017), order denying stay, 160 FERC ¶ 61,015 (2017), reh’g denied, 161 FERC ¶ 61,255 (Dec. 13, 2017) (“Atlantic Bridge Project Order”).

102 The following facilities placed into service: Southeast Discharge Take-up and Relay (Fairfield County, CT); Modified Oxford

Compressor Station (New Haven County, CT); Modified Chaplin Compressor Station (Windham County, CT); Modified Danbury (CT) Meter Station; and Modified Stony Point Compressor Station (Rockland County, NY).

103Algonquin Gas Transmission, LLC, 158 FERC ¶ 61,061 (Oct. 27, 2017).



Page 32 41536280.182

Authorization to proceed with construction of additional Project segments requested on Oct. 31, 2017. Detailed information regarding construction activities can be found in the weekly construction reports filed in this docket.

• Constitution Pipeline (CP13-499) and Wright Interconnection Project (CP13-502)

Constitution Pipeline Company and Iroquois Gas Transmission (Wright Interconnection) concurrently filed for Section 7(c) certificates on June 13, 2013.

650,000 Dth/d of firm capacity from Susquehanna County, PA (Marcellus Shale) through NY to Iroquois/Tennessee interconnection (Wright Interconnection).

New 122-mile interstate pipeline.

Two firm shippers: Cabot Oil & Gas and Southwestern Energy Services.

Final EIS completed on Oct 24, 2014.

Certificates of public convenience and necessity granted Dec 2, 2014. By letter order issued July 26, 2016, the Director of the Division of Pipeline

Certificates (Director) granted Constitution’s requested two-year extension of time to construct the project.

Construction was expected to begin Spring 2016 (after final Federal Authorizations), but has been plagued by delays (see below).

On April 22, 2016, New York State Department of Environmental Conservation (NY DEC) denied Constitution’s application for a Section 401 permit under the Clean Water Act. On August 18, 2017, the 2nd Circuit denied Constitution’s petition for review of

the NY DEC decision, concluding that (1) the court lacked jurisdiction over the Constitution’s claims to the extent that they challenged the timeliness of the decision; and (2) the NY DEC acted within its statutory authority in denying the certification, and its denial was not arbitrary or capricious.

On May 16, 2016, the New York Attorney General filed a complaint against Constitution at the FERC (CP13-499) seeking a stay of the December 2014 order granting the original certificates, as well as alleging violations of the order, the Natural Gas Act, and the Commission’s own regulations due to acts and omissions associated with clear-cutting and other construction-related activities on the pipeline right of way in New York. In July 2016, the FERC rejected the NY AG’s filing as procedurally deficient, and

declined to stay of the Certificate Order

Tree felling and site preparation continues, but the long-term status of the pipeline is currently unknown. Constitution will submit its monitoring reports monthly rather than weekly until activities resume in 2018.

• Non-New England Pipeline Proceedings The following pipeline projects could affect ongoing pipeline proceeding in New England and around the

country:

• Southeast Market Pipelines Project (CP14-554, CP15-16, CP15-17)

Florida Southeast Connection, LLC, Transcontinental Gas Pipe Line Company, LLC and Sabal Trail Transmission, LLC (Sabal Trail) filed for a Section 7(c) certificates in Sept. – Nov. 2014.

The three separate but connected natural gas transmission pipeline projects project total approximately 685.5 miles of natural gas transmission pipeline and provide transportation service for up to approximately 1.1 billion cubic feet per day of natural gas to markets in Florida and the southeast United States .



Page 33 41536280.182

Certificates of public convenience and necessity were granted Feb. 2, 2016.104

Project construction began in August 2016, and in June and July 2017, Commission Staff authorized the pipelines to commence service on completed facilities.

On August 22, 2017, the DC Circuit vacated and remanded the FERC’s certificate order, holding that the FERC’s environmental review of the project failed to adequately consider the downstream effects of greenhouse gas emissions resulting from increased power generation.105

The DC Circuit held that FERC must either quantify and consider the project’s downstream carbon emissions or explain in more detail why it cannot do so. According to the court, quantification would permit the agency to compare the emissions from this project to emissions from other projects, to total emissions from the state or the region, or to regional or national emissions-control goals. Without such comparisons, it is difficult to see how FERC could engage in “informed decision making” with respect to the greenhouse-gas effects of this project, or how “informed public comment” could be possible.

This opinion could have significant consequences for future pipeline proceedings at FERC.

On September 27, 2017, the FERC issued a Draft Supplemental EIS, estimating the pipeline would potentially increase the Florida GHG emission inventory between 3.7 and 9.7 percent. In the supplemental EIS, the FERC stated that it “could not find a suitable

method to attribute discrete environmental effects to GHG emissions.”

• Millennium Pipeline Valley Lateral Project (CP16-17)

On July 21, 2017, Millennium Pipeline Company, L.L.C. (Millennium) filed a Request for Notice to Proceed with Construction of its Valley Lateral Project in Orange County, New York. The Valley Lateral Pipeline will connect the existing Millennium Pipeline to the

680 MW CPV Valley Energy Center.

To receive a notice to proceed, Millennium was required to demonstrate that it had obtained all federally-required environmental permits and authorizations, including authorizations under the Clean Water Act (CWA). Millennium stated that the New York State Department of Environmental Conservation (New York DEC) had waived its authority to issue a water quality certification under Section 401 of the CWA by failing to act before the statutorily-imposed deadline. In August 2017, the NY DEC denied the water quality certification to the Valley

Lateral Project, citing the D.C. Circuit’s recent ruling in Sierra Club v. FERC and the FERC’s “lack of a complete environmental review.”

By Letter Order issued on September 15, 2017, the FERC agreed with Millennium, finding that the New York DEC had waived its authority to issue or deny a water quality certification. Because the NY DEC had received Millennium’s Section 401 certification in November 2015, but did not rule on it until August 2017, FERC ruled that NY DEC, as the certifying agency, had therefore failed to act within the statutory timeframe and had

104Fla. Southeast Connection, LLC, 154 FERC ¶ 61,080, 61 (Feb. 2, 2016) (order issuing certificate).

105Sierra Club v. FERC, 2017 U.S. App. LEXIS 15911 (D.C. Cir. Aug. 22, 2017).



Page 34 41536280.182

waived its certification authority.106 The FERC’s order effectively nullifies the NY DEC’s August 2017 rejection of the water quality certification. The NY DEC, on October 13, 2017, filed a Request for Rehearing and Stay of the

FERC’s September 15, 2017, Order. On November 15, the FERC denied the requests for rehearing, stay, and rescission.107

Millennium sought, and on October 3, 2017, the FERC granted, a one year extension of time to complete construction of the Valley Lateral Project and make it available for service by November 2018.

On October 27, 2017, the FERC issued a Notice to Proceed, granting Millennium’s request to begin construction of the Valley Lateral. The NY DEC, on October 30, 2017, filed a Request for Stay of the Notice to

Proceed. The November 15 Order also denied the October 30 request for stay.108

• Northern Access Project (CP15-115)

On Feb. 3, 2017, the FERC issued an order authorizing National Fuel Gas Supply Corporation and Empire Pipeline, Inc. to construct and operate pipeline, compression, and ancillary facilities in McKean County, Pennsylvania, and Allegany, Cattaraugus, Erie, and Niagara Counties, New York (Northern Access Project)

In March 2017, Allegheny Defense Project and Sierra Club (collectively Allegheny) filed a request for rehearing of the FERC’s order and on August 31, 2017, FERC issued an Order Denying Stay Consistent with its previous authorization, FERC found no evidence of

irreparable harm in letting the project go forward.

Despite the FERC’s Order, the project remains halted pending the outcome of National Fuel’s fight with the NY DEC’s April denial of a Clean Water Act permit. NY DEC found National Fuel’s application for a water quality certification, as well

as for stream and wetlands disturbance permits, failed to comply with water regulations aimed at protecting wetlands and wildlife and that the pipeline failed to explore construction alternatives.


• Massachusetts Emissions Allowance Auctions: Stakeholder Input on Auction Design Parameters In an action that could have implications for the New England Markets, the Massachusetts (MA)

Department of Environmental Protection (“MassDEP”) issued on August 11, 2017 final regulations to ensure that MA will meet the 2020 statewide greenhouse gas (“GHG”) emissions limits mandated by MA’s 2008 Global Warming Solutions Act (“GWSA”). Section 7.74109 of those regulations reduces carbon dioxide (“CO2”) emissions from MA-based power plants by imposing an annually declining aggregate emissions cap on MA’s 21 large fossil

106Millennium Pipeline Co., L.L.C., 160 FERC ¶ 61,065 (Sept. 15, 2017), reh’g denied, 161 FERC ¶ 61,186 (Nov. 15, 2017).

107Millennium Pipeline Co., L.L.C., 161 FERC ¶ 61,186 (Nov. 15, 2017) (“November 15 Order”).

108 On Oct. 30, 2017, NY DEC also petitioned the United States Court of Appeals for the Second Circuit for a temporary stay of

the FERC’s Notice to Proceed until the FERC acts on NY DEC’s request for rehearing of the Declaratory Order. In re New York State Department of Environmental Conservation v. FERC, 2d Cir. No. 17-3503, Petitioner’s Emergency Petition for a Writ of Prohibition (Oct. 30, 2017) (Emergency Petition). NY DEC also requested the court to stay the effectiveness of the Notice to Proceed on an interim basis while the court considers the merits of its petition. Id. at 34. On Nov. 2, 2017, the court granted an administrative stay pending consideration of the petition by the next available three-judge panel. In re New York State Dep’t of Envtl. Conservation v. FERC, 2d Cir. No. 17-3503 (Nov. 2, 2017). NY DEC’s Emergency Petition is pending at the court.

109 Additional information about 310 CMR 7.74 (Reducing CO2 Emissions from Electricity Generating Facilities) is available at:

http://www.mass.gov/eea/agencies/massdep/climate-energy/climate/ghg/electricity-generatoremissions-limits.html.



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fuel-fired generators. Operators of those facilities will have to offset their CO2 production with allowances (a limited authorization to emit one metric ton of CO2 in a calendar year). Allowances will be allocated directly in 2018 based on historical generation. Beginning with compliance year 2019, Section 7.74 requires auctioning of the emissions allowances that facilities must use to comply with the regulation. Allowances may be traded between facilities and a limited quantity may be banked from year to year.

On December 15, 2017, MassDEP filed final amendments to correct errors for two facilities in the 2018 allowance allocations. These amendments were published in the Massachusetts register on December 29, 2017. In addition, MassDEP has committed to post on its website compliance forms and an “FAQ” document.

The allowance tracking system will be deployed In the Spring of 2018. Detailed instructions for regulated facilities will be provided at that time. Stakeholder comments on the auction design solicited in the Fall of 2017 will be considered as the MassDEP develops procedures in preparation for allowance auctions that begin in 2019. MassDEP anticipates additional opportunities for stakeholders to participate in the auction design process in 2018, possibly including an opportunity to comment on proposed regulatory amendments. MassDEP is also in the process of soliciting market monitoring services, and will hire an auction administrator in 2018. Questions regarding 310 CMR 7.74 can be directed to Will Space ([email protected]; 617-292-5610).

• NG Advantage (NY) Permit Challenge (RJI No.: 2017-0799; RJI No.: 2017-0800) Chenango Valley Central School District and various nearby residents Petitioners have initiated

proceedings against the Town of Fenton, New York Planning Board and NG Advantage, LLC to halt NG Advantage, LLC’s (“NG Advantage”) proposed construction of a natural gas compressor facility that would extract gas up to 4000 psi and transport the compressed natural gas to NG Advantage customers. Petitioners are concerned that the project infringes on the rights of those who live near the transfer station. They are specifically concerned about the site's proximity to schools, and the burden it could place on local roads.

A judicial decision on whether the Town of Fenton followed proper procedures with respect to zoning laws in approving the Project has been held in reserve while Supreme Court Judge Ferris Lebous reviews oral arguments and submissions. The Project is currently halted pending judgment.

XV. Federal Courts

The following are matters of interest, including petitions for review of FERC decisions in NEPOOL-related proceedings, that are currently pending before the federal courts (unless otherwise noted, the cases are before the U.S. Court of Appeals for the District of Columbia Circuit). An “**” following the Case No. indicates that NEPOOL has intervened or is a litigant in the appeal. The remaining matters are appeals as to which NEPOOL has no organizational interest but that may be of interest to Participants. For further information on any of these proceedings, please contact Pat Gerity (860-275-0533; [email protected]).

• FCM Resource Retirement Reforms (17-1275) Underlying FERC Proceedings: ER16-551110

Petitioner: Constellation On December 28, 2017, Constellation (“Petitioner”) petitioned the DC Circuit Court of Appeals for

review of the FERC’s FCM Resource Retirement Reforms orders. Among other submissions, Constellation must file by February 1, 2018 a docketing statement, statement of issues, and any procedural motions. Dispositive motions must be filed by February 16. Appearances by others in this case must be filed by February 1.

110ISO New England Inc., 155 FERC ¶ 61,029 (Apr. 12, 2016) (“Resource Retirement Reforms Order”), reh’g and clarif. denied,

161 FERC ¶ 61,115 (Oct. 30, 2017).




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• Demand Curve Changes (17-1110**) Underlying FERC Proceedings: ER14-1639111

Petitioners: NextEra, NRG, PSEG On April 3, 2017, NextEra, NRG and PSEG (“Petitioners”) again petitioned the DC Circuit Court of

Appeals for review of the FERC’s Demand Curve orders, which, as previously reported, had been remanded back to the FERC at the FERC’s request following the first appeal by Petitioners. Petitioners’ statement of issues and other initial procedural submissions, as well as the FERC’s initial submissions, were filed May 8. The Clerk granted on June 2 the interventions filed by NEPOOL, NESCOE, CT PURA, and CPV. Petitioner’s Brief was filed on September 8, and corrected on September 18 (for compliance with the Court’s rules on acronyms and abbreviations). Respondent FERC’s Brief was filed on November 21, 2017. On November 28, NRDC and CLF jointly moved for leave to participate as amici curiae and filed an amicus curiae brief in support of the FERC On December 5, the Court granted NRDC/CLF leave to participate as amici curiae and the Clerk lodged the Nov 28 amicus curiae brief. Intervenors for Respondent Brief was filed by NESCOE, CT PURA and CPV Towantic on December 12, 2017. Petitioner’s Reply Brief is to be filed on January 11, 2018; Deferred Appendix, January 25; and Final Briefs, February 1, 2018.

• FCA10 Results (16-1408) and FCA9 Results (16-1068) Underlying FERC Proceedings: ER16-1041112 ER15-1137113

Petitioners: UWUA Local 464 and Robert Clark UWUA Local 464 and Robert Clark (“Petitioners”) filed petitions for review of the FERC’s orders on

the FCA10 and FCA9 Results Filings, consolidated by the Court on January 31, 2017. With Final Briefs submitted on June 26, 2017, all briefing is complete. On December 14, the court scheduled these cases for oral argument on February 9, 2018. The composition of the argument panel will be identified on or about January 8, 2018.

• NEPGA PER Complaint and FCM Jump Ball and Compliance Proceedings (16-1023/1024) Underlying FERC Proceeding: ER14-1050;114 EL14-52;115 EL15-25116

Petitioner: NEPGA As previously reported, NEPGA filed, on January 19, 2016, a petition for review of the FERC’s orders

on NEPGA’s first PER Complaint. On February 24, 2016, the Court granted NEPGA’s motion to consolidate this proceeding with 16-1024. Briefing was completed on November 28, 2016. Oral argument was held October 27, 2017 before Judges Griffith, Sentelle and Randolph. This matter is now pending before the Court.

• Base ROE Complaints II & III (2012 & 2014) (15-1212) Underlying FERC Proceedings: EL13-33; EL14-86117

Appellants: New England Transmission Owners As previously reported, the TOs filed a petition for review of the FERC’s orders in the 2012 and 2014 ROE

complaint proceedings on July 13, 2015. On August 14, 2015, the TOs filed an unopposed motion to hold this

111 147 FERC ¶ 61,173 (May 30, 2014) (Demand Curve Order); 150 FERC ¶ 61,065 (Jan. 30, 2015) (Demand Curve Clarification

Order); 155 FERC ¶ 61,023 (Apr. 8, 2016) (Demand Curve Remand Order); 158 FERC ¶ 61,138 (Feb. 3, 2017) (Demand Curve Remand Rehearing Order).

112 155 FERC ¶ 61,273 (June 16, 2016); 157 FERC ¶ 61,060 (Oct. 27, 2016).

113 153 FERC ¶ 61,378 (Dec. 30, 2015); 151 FERC ¶ 61,226 (June 18, 2015).

114 153 FERC ¶ 61,224 (Nov. 19, 2015); 153 FERC ¶ 61,223 (Nov. 19, 2015); 147 FERC ¶ 61,172 (May 30, 2014).

115 153 FERC ¶ 61,222 (Nov. 19, 2015); 150 FERC ¶ 61,053 (Jan. 30, 2015).

116 153 FERC ¶ 61,222 (Nov. 19, 2015); 150 FERC ¶ 61,053 (Jan. 30, 2015).

117 147 FERC ¶ 61,235 (June 19, 2014); 149 FERC ¶ 61,156 (Nov. 24, 2014); 151 FERC ¶ 61,125 (May 14, 2015).



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case in abeyance pending final FERC action on the 2012 and 2014 ROE Complaints (see Section I above). On August 20, 2015, the Court granted the TOs’ motion to hold the case in abeyance, subject to submission of status reports every 90 days. The most recent status report, the ninth such report filed, was filed on November 13, 2017. In that report, the parties again indicated, ultimately, that the proceedings upon which the TOs based their request for abeyance of this appeal remain ongoing. This case continues to be held in abeyance.

• FCM Pricing Rules Complaints (15-1071**, 16-1042) (consol.) Underlying FERC Proceeding: EL14-7,118 EL15-23119

Petitioners: NEPGA, Exelon On March 31, 2015, NEPGA filed a petition for review of the FERC’s orders on NEPGA’s FCM

Administrative Pricing Rules Complaint. Following briefing, oral argument was held October 6, 2017 before Judges Srinivasan, Wilkins and Sentelle. This matter is now pending before the Court.

118 150 FERC ¶ 61,064 (Jan. 30, 2015); 146 FERC ¶ 61,039 (Jan. 24, 2014).

119 154 FERC ¶ 61,005 (Jan. 7, 2016); 150 FERC ¶ 61,067 (Jan. 30, 2015).



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INDEX Status Report of Current Regulatory and Legal Proceedings

as of January 3, 2018


206 Proceeding: RNS/LNS Rates and Rate Protocols ............................................................ (EL16-19) ................................ 6 Base ROE Complaint I-IV: TOs’ Motion to Dismiss/Consolidate ........................................... (EL16-64 et al.) ....................... 5 Base ROE Complaints II & III (2012 & 2014) (Consolidated) ................................................. (EL13-33 and EL14-86) ........... 6 Base ROE Complaint IV (2016) .............................................................................................. (EL16-64) ................................ 5 Calpine/LS Power Delayed Resource Complaint .................................................................. (EL18-53) ................................ 2 Clear River Schedule 11 O&M Complaint ............................................................................. (EL18-31) ................................ 2 NEPGA PER Adjustment Complaint ...................................................................................... (EL16-120) .............................. 3 NEPGA PER Adjustment Complaint Settlement Agreement................................................. (ER17-2153) ........................... 4


206 Proceeding: RNS/LNS Rates and Rate Protocols ............................................................ (EL16-19) ................................ 6 Base ROE Complaints II & III (2012 and 2014) (Consolidated) .............................................. (EL13-33 and EL14-86) ........... 6 Base ROE Complaint IV (2016) .............................................................................................. (EL16-64) ................................ 5 Calpine/LS Power Delayed Resource Complaint .................................................................. (EL18-53) ................................ 2 Emera MPD OATT Attachment J Revision ............................................................................ (ER18-210) ............................. 9 Exelon Additional Cost Recovery Compliance Filing ............................................................. (ER17-933) ............................. 9 FCA12 Qualification Informational Filing .............................................................................. (ER18-264) ............................. 8 ICR-Related Values and HQICCs – 2021-22 Capacity Commitment Period .......................... (ER18-263) ............................. 8 ICR-Related Values and HQICCs – Annual Reconfiguration Auctions ................................... (ER18-371) ............................. 7 NEPGA PER Adjustment Complaint ...................................................................................... (EL16-120) .............................. 3 NEPGA PER Adjustment Complaint Settlement Agreement................................................. (ER17-2153) ........................... 4 TOs’ Opinion 531-A Compliance Filing Undo ........................................................................ (ER15-414) ............................. 9


2013/14 Winter Reliability Program Remand Proceeding .................................................... (ER13-2266) ......................... 11 ART Market Rule Changes .................................................................................................... (ER18-455) ........................... 10 Calpine/LS Power Delayed Resource Complaint .................................................................. (EL18-53) ................................ 2 CONE & ORTP Updates ......................................................................................................... (ER17-795) ........................... 11 NEPGA PER Adjustment Complaint ...................................................................................... (EL16-120) .............................. 3 NEPGA PER Adjustment Complaint Settlement Agreement................................................. (ER17-2153) ........................... 4 Waiver Request: DR Auditing Requirements (CPower) ........................................................ (ER18-185) ........................... 10 Waiver Request: Dispatchable Resources RTU Requirement (McCallum Enterprises) ........ (ER17-1615) ......................... 10

IV. OATT Amendments/Coordination Agreements






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VI. Schedule 20/21/22/23 Updates

Eversource Reorganization Tariff Changes ........................................................................... (ER18-132) ........................... 13 Schedule 20A-GMP Brookfield Complaint ............................................................................ (EL18-52) .............................. 12 Schedule 21-EM: Bangor Hydro/Maine Public Service Merger-Related Costs Recovery ..... (ER15-1434 et al.) ................ 13 Schedule 21-EM: Stored Solar J&WE LSA ............................................................................. (ER18-387) ........................... 12 Schedule 21-NEP: National Gird/Granite Reliable Power RFA ............................................. (ER18-346) ........................... 13 Schedule 22: Clear River LGIA ............................................................................................... (ER18-349) ........................... 12

VII. NEPOOL Agreement/ Participants Agreement Amendments



IMM Quarterly Markets Reports - Summer 2017 ................................................................. (ZZ17-4) ................................ 15 Opinion 531-A Local Refund Report: FG&E .......................................................................... (EL11-66) .............................. 15 Opinions 531-A/531-B Local Refund Reports ....................................................................... (EL11-66) .............................. 15 Opinions 531-A/531-B Regional Refund Reports .................................................................. (EL11-66) .............................. 15


December 2017 Membership Filing ..................................................................................... (ER18-353) ........................... 15 January 2018 Membership Filing .......................................................................................... (ER18-539) ........................... 15 Suspension Notice – Plant-E Corp. ....................................................................................... (not docketed) ..................... 16


FERC Staff Report on CIP v5 Reliability Standards Audits ..................................................... (not docketed) ..................... 16 NOPR: Cyber Security Incident Reporting Reliability Standards ........................................... (RM18-2) .............................. 16 NOPR: New Rel. Standards: PRC-027-1 and PER-006-1 ........................................................ (RM16-22) ............................ 18 NOPR: Revised Rel. Standard: CIP-003-7 .............................................................................. (RM17-11) ............................ 17 NOPR: Revised Rel. Standards: EOP-004-4, EOP-005-3, EOP-006-3, EOP-008-2 .................. (RM17-12) ............................ 17 NOPR: Revised Rel. Standard: MOD-001-2 ........................................................................... (RM14-7) .............................. 18 Rules of Procedure Changes (Appendix 3D - Registered Ballot Body Criteria) ..................... (RR18-1) ............................... 19 Rules of Procedure Changes (Sections 600 and 900) ........................................................... (RR17-6) ............................... 19 Revised Rel. Standards: CIP-005-6, CIP-010-3, CIP-013-1 ..................................................... (RM17-13) ............................ 17

XI. Misc. Regional Interest

203 Application: Calpine/ECP ............................................................................................... (EC17-182) ........................... 20 203 Application: Dynegy/Vistra ............................................................................................ (EC18-23) ............................. 19 203 Application: GenOn Reorganization .............................................................................. (EC17-152) ........................... 20 203 Application: Green Mountain Power/ENEL Hydros ....................................................... (EC17-76) ............................. 20 203 Application: NSTAR/WMECO Merger ............................................................................ (EC17-62) ............................. 20 203 Application: PSNH/Granite Shore .................................................................................. (EC18-12) ............................. 20 203 Application: PSNH/HSE Hydro NE .................................................................................. (EC18-42) ............................. 19 Anbaric’s Ocean Grid Project: Transmission Rights at Negotiated Rates ............................. (ER18-435) ........................... 22 D&E Agreement: Pootatuck Ring Bus Expansion .................................................................. (ER18-111) ........................... 23 D&E Agreement Cancellation: NSTAR/Essential Power Newington ..................................... (ER18-330) ........................... 22 FERC Audit of ISO-NE ............................................................................................................ (PA16-6) ............................... 23 FERC Enforcement Action: Formal Investigation

(MISO Zone 4 Planning Resource Auction Offers) .................................................. (IN15-10) .............................. 23



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IA: CL&P/Woods Hill Solar .................................................................................................... (ER18-316) ........................... 23 IA: PSNH/Pontook ................................................................................................................. (ER17-2449) ......................... 23 LGIA: Emera Maine/Penobscot Energy Recovery Co ........................................................... (ER18-505) ........................... 21 MOPR-Related Proceedings (NYISO, PJM) ............................................................................ (EL13-62; EL16-49) ............... 21 NEP/HQUS Phase I/II HVDC-TF Service Agreement .............................................................. (ER18-388) ........................... 22

XII. Misc: Administrative & Rulemaking Proceedings

DOE-Initiated Proposal: Grid Reliability & Resilience Pricing Rule ....................................... (RM18-1) .............................. 24 NOI: FERC’s Policy for Recovery of Income Tax Costs & ROE Policies .................................. (PL17-1) ................................ 24 NOPR: Data Collection for Analytics & Surveillance and MBR Purposes .............................. (RM16-17) ............................ 27 NOPR: Electric Storage Participation in RTO/ISO Markets ................................................... (RM16-23; AD16-20) ............ 27 NOPR: Fast-Start Pricing in RTO/ISO Markets ...................................................................... (RM17-3) .............................. 26 NOPR: LGIA/LGIP Reforms .................................................................................................... (RM17-8) .............................. 25 NOPR: Primary Frequency Response -

Essential Reliability Services and the Evolving Bulk-Power System ....................... (RM16-6) .............................. 28 NOPR: Uplift Cost Allocation and Transparency in RTO/ISO Markets .................................. (RM17-2) .............................. 26 Order 833: Critical Energy/Electric Infrastructure Information (CEII) Procedures ............... (RM16-15) ............................ 27 State Policies & Wholesale Markets Operated by ISO-NE, NYISO, PJM ............................... (AD17-11) ............................. 24 Third Supplement to Lease Agreement: UI/CT DOT ............................................................ (ER18-454) ........................... 21


Algonquin EDC Capacity Release Bidding Requirements Exemption Request ..................... (RP16-618) ........................... 28 Enforcement Action: BP Initial Decision ............................................................................... (IN13-15) .............................. 29 Enforcement Action: Rover-Staff Notice of Alleged Violation .............................................. (not docketed) ..................... 31 Enforcement Action: Total Gas & Power North America, Inc. .............................................. (IN12-17) .............................. 29 New England Pipeline Proceedings ...................................................................................... ............................................. 31 Non-New England Pipeline Proceedings .............................................................................. ............................................. 32


Massachusetts Emissions Allowance Auctions: Stakeholder Input on Auction Design Parameters .................................. 34 NG Advantage (NY) Permit Challenge .................................................................................. ............................................. 35

XV. Federal Courts

Base ROE Complaints II & III (2012 & 2014) ......................................................................... 15-1212 (DC Cir.) .................. 36 Demand Curve Changes ....................................................................................................... 17-1110 (DC Cir.) .................. 36 FCA10 Results and FCA9 Results ........................................................................................... 16-1068/16-1408 (DC Cir.) ... 36 FCM Pricing Rules Complaints .............................................................................................. 15-1071/16-1042 (DC Cir.) ... 37 FCM Resource Retirement Reforms ..................................................................................... (17-1275) ............................. 35 NEPGA PER Complaint and FCM Jump Ball and Compliance Proceedings ........................... 16-1023/1024 (DC Cir.) ........ 36

jan 5, 2018 meeting, agenda item #1 marked to show … · 1/5/2018 · committee, nepool vote, and...

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